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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
___________________
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS PURSUANT TO
SECTIONS 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____________ to ____________
Commission File Number: 0-23431
MILLER EXPLORATION COMPANY
(Exact Name of Registrant as Specified in Its Charter)
DELAWARE 38-3379776
(State or Other Jurisdiction of (I.R.S. Employer Identification No.)
Incorporation or Organization)
3104 LOGAN VALLEY ROAD, TRAVERSE CITY, MICHIGAN 49685-0348
(Address of Principal Executive Offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (616) 941-0004
Securities registered pursuant to Section 12(g) of the Act:
TITLE OF EACH CLASS
Common Stock, $0.01 Par Value
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.
Yes __X__ No _____
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Number of shares outstanding of the registrant's Common Stock, $0.01 par
value (excluding shares of treasury stock) as of April 13, 1999: 12,560,124
The aggregate market value of the registrant's voting stock held by non-
affiliates of the registrant as of April 13, 1999: $13,351,411.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the Company's June 3, 1999
annual meeting of stockholders are incorporated by reference in Part III of
this Form 10-K
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FORWARD-LOOKING STATEMENTS
This annual report on Form 10-K includes forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. Forward-looking statements can
be identified by the words "anticipates," "expects," "intends," "plans,"
"projects," "believes," "estimates" and similar expressions. Miller
Exploration Company ("Miller" or the "Company") has based the forward-
looking statements relating to its operations on current expectations,
estimates and projections about the Company and the oil and gas industry in
general. These statements are not guarantees of future performance and
involve risks, uncertainties and assumptions that the Company cannot
predict. In addition, the Company has based many of these forward-looking
statements on assumptions about future events that may prove to be
inaccurate. Accordingly, the Company's actual outcomes and results may
differ materially from what is expressed or forecasted in the forward-
looking statements. Any differences could result from a variety of factors
including the following: fluctuations in crude oil and natural gas prices;
failure or delays in achieving expected production from oil and gas
development projects; uncertainties inherent in predicting oil and gas
reserves and oil and gas reservoir performance; lack of exploration
success; disruption or interruption of the Company's production facilities
due to accidents or political events; liability for remedial actions under
environmental regulations; disruption to the Company's operations due to
untimely or incomplete resolution of Year 2000 issues by the Company or
other entities; liability resulting from litigation; world economic and
political conditions; and changes in tax and other laws applicable to the
Company's business.
PART I
ITEM 1. BUSINESS.
The Company is an independent oil and gas exploration and production
company with exploration efforts concentrated primarily in four regions:
the Mississippi Salt Basin, the onshore Gulf Coast region of Texas and
Louisiana, the Blackfeet Indian Reservation in Northwest Montana and the
Michigan Basin. Miller emphasizes the use of 3-D seismic data analysis and
imaging, as well as other emerging technologies, to explore for and develop
oil and natural gas in its core exploration areas. Miller is the successor
to Miller Oil Corporation ("MOC"), an independent oil and natural gas
exploration and production business first established in Michigan by
members of the Miller family in 1925. References herein to the "Company"
or "Miller" are to Miller Exploration Company, a Delaware corporation, and
its subsidiaries and predecessors.
The Company was organized in connection with the combination (the
"Combination Transaction") of MOC and interests in oil and natural gas
properties owned by certain affiliated entities and interests in such
properties owned by certain business partners and investors (collectively,
the "Combined Assets").
The Combined Assets consist of MOC, interests in oil and natural gas
properties from oil and natural gas exploration companies beneficially
owned by members of the Miller family (the "Affiliated Entities") and
interests in such properties owned by certain business partners and
investors, including Amerada Hess Corporation ("AHC"), Dan A. Hughes, Jr.
and SASI Minerals Company. No assets other than those in which MOC or the
Affiliated Entities had an interest were part of the Combined Assets. The
Company and the owners of the Combined Assets entered into separate
agreements that provided for the issuance of approximately 6.9 million
shares of the Company's Common Stock and the payment of $48.8 million (net
of post-closing adjustments) in cash to certain participants in the
Combination Transaction in exchange for the Combined Assets. The issuance
of the shares and the cash payment were completed upon consummation of the
Company's initial public offering.
The Combination Transaction closed on February 9, 1998 in connection
with the closing of the Company's initial public offering of 5.5 million
shares of Common Stock (the "Offering"). The Offering, including the sale
of an additional 62,500 shares of Common Stock by the Company on March 9,
1998 pursuant to the exercise of the underwriters' over-allotment option,
resulted in net proceeds to the Company of approximately $40.4 million
after expenses.
Miller incurred expenditures for exploration and development activity
of $47.0 million with respect to the Company's interest in 33 gross wells
(14.0 net to the Company) for the year ended December 31, 1998 and $27.0
million (on a pro forma basis) with respect to the Company's interest in 31
gross wells (6.6 net to the Company) for the year ended December 31, 1997.
Estimated proved reserves attributable to the Combined Assets have
increased 78%, from 19.6 billion cubic feet of natural gas equivalent
("Bcfe") as of January 1, 1995 to 34.9 Bcfe as of December 31, 1998. The
Company has budgeted a significant decrease in drilling activity and
currently plans to drill eight wells (3.3 net to the Company) in 1999, the
majority of which are exploratory wells in the Mississippi Salt Basin. The
Company's capital expenditure budget for both exploration and development
activity in all of its areas of concentration is an unrisked $10.6 million
for 1999.
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CORE EXPLORATION AND DEVELOPMENT REGIONS
MISSISSIPPI SALT BASIN
The Company believes that the Mississippi Salt Basin, which extends
from Southwestern Alabama across central Mississippi into Northeastern
Louisiana, has a significant number of under-developed salt domes. A salt
dome is a generally dome-shaped intrusion into sedimentary rock that has a
mass of salt as its core. The impermeable nature of the salt dome structure
may act as a mechanism to trap hydrocarbons migrating through surrounding
rock formations. These geologic structures were formed by the upward
thrusting of subsurface salt accumulations towards the surface. Such
structures generally are found in groups in geologic basins that provide
the necessary conditions for their formation. Salt domes are typically
subsurface structures that are easily identified with seismic surveys, but
occasionally are visible as surface expressions. The salt domes of the
Mississippi Salt Basin were formed in the Cretaceous period. These salt
domes range in diameter from one-half mile to three miles and vertically extend
from 2,000 feet in depth to nearly 20,000 feet in depth. Salt domes
similar to those of the Mississippi Salt Basin are a significant cause for
major oil and gas accumulations in the Texas and Louisiana Gulf Coast,
Northern Louisiana, East Texas and the offshore Gulf of Mexico. This basin
has produced substantial amounts of oil and natural gas and continues to be
a very active exploration region. Oil and natural gas discovered in the
Mississippi Salt Basin have been produced from reservoirs with various
stratigraphic and structural characteristics, and may be found in multiple
horizons from approximately 3,500 feet to 19,000 feet in depth. Oil and
natural gas reserves around salt domes have been encountered in the Eutaw,
Lower Tuscaloosa, Washita-Fredericksburg, Paluxy, Rodessa, Sligo, Hosston
and Cotton Valley formations, all of which are normally pressured. The
Company owns undeveloped leasehold interests in 72,365 gross acres (45,867
net to the Company) covering 22 known salt domes and related salt
structures. The Company's primary working interest partner in this basin
is Key Production Company, Inc. ("Key").
Until the late 1980s, geological models of the salt domes in the
Mississippi Salt Basin generally assumed that either the extreme and rapid
growth of the salt structure breached the seals of any formations trapping
hydrocarbons against the domes or that the growth of the salt domes
occurred after hydrocarbons had migrated through the region, in either
case, leaving the formations around the salt domes nonproductive. From
1987 to 1991, Oryx Energy Corporation ("Oryx") drilled three successful
wells on Mississippi salt dome structures, proving that the flanks of these
salt domes were productive. AHC purchased Oryx's entire interest in this
area, and in 1993 MOC acquired a 12.5% working interest from AHC in
approximately 35,000 gross acres surrounding seven domes. As part of the
Combination Transaction, the Company acquired all of AHC's reserves and
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leasehold interests in these properties, resulting in an approximate 87.5%
working interest in the aggregate to the Company. The Company selectively
reprocessed an extensive 2-D seismic database that had been acquired over these
salt dome prospects, and further acquired new 2-D seismic to improve the
selection of the drill sites along the flanks of the salt domes. Based on the
positive results of the first several prospects drilled, MOC acquired leasehold
interests around 15 additional salt domes and related salt structures that
it considered to be prospective.
The Company believes that the key to exploiting salt dome prospects
effectively is the accurate delineation of a salt dome's flanks, with the
recognition of fault patterns and the location of fault blocks with large
reserve potential. While the reinterpreted 2-D seismic data provided the
Company's explorationists with better imaging of a salt dome's subsurface
structures, it proved to have limitations in defining the exact locations
of the flanks of a salt dome. The Company believes that all of its
unsuccessful salt dome wells have either encountered the interior salt core
of the salt dome or were too far off structure to encounter the anticipated
hydrocarbon trap. In 1998, the Company acquired approximately 400 square
miles of 3-D seismic data in the Mississippi Salt Basin at a cost of nearly
$12.0 million. Based on initial interpretations of the data, the Company
is encouraged that the new 3-D seismic imaging will more effectively image
the edge of the salt dome, identifying areas that had not been seen on the
2-D seismic, in addition to providing better definition of the size and
location of future drilling targets. The Company has continued to use
technologically advanced seismic data processing methods to reinterpret
existing regional 2-D seismic data and analyze and interpret newly acquired
2-D seismic data. The Company intends to utilize its reprocessed 2-D
seismic database to complement its recently acquired 3-D seismic data.
The Company owns an interest in 12 producing wells in the Mississippi
Salt Basin that had aggregate average production as of December 31, 1998 of
49.1 million cubic feet of natural gas equivalent per day ("MMcfe/d") gross
(27.1 MMcfe/d net to the Company) at depths ranging from 10,800 to 17,300
feet. Since the Company began its exploration activity in Mississippi in
1993, it has participated in 30 wells drilled around 10 salt dome
structures, 13 of which (43%) established commercial production. At
December 31, 1998, the Company also was in the process of drilling and/or
completing two wells (1.3 net to the Company). The Company has six gross
wells (2.4 net to the Company) budgeted in 1999 for the Mississippi Salt
Basin with a capital expenditure budget of $8.3 million, including $1.4
million for completion and final processing of the 3-D seismic surveys
around 10 salt domes in 1999. This will provide 3-D seismic data on four
of the six Mississippi Salt Basin wells budgeted for 1999. As of
December 31, 1998, the Company had established 44.9 Bcfe gross (22.5 Bcfe
net to the Company) of estimated proved reserves.
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ONSHORE GULF COAST OF TEXAS AND LOUISIANA
The Company believes that the onshore Gulf Coast area of Texas and
Louisiana is a high potential, multi-pay region that lends itself to 3-D
seismic-supported exploration due to its substantial structural and
stratigraphic complexity. The Company has been an active working interest
partner in select projects proposed by Dan A. Hughes Company (the "Hughes
Company") in Zapata, Webb, Duval, Karnes and McMullen Counties, Texas and
Cameron and Terrebonne Parishes, Louisiana, under an exploration agreement
to which the Company has been a party since 1994. Before accepting a
proposed prospect under the agreement, the Company undertakes a thorough
evaluation, considering geographic location, scale, geological and
geophysical model, anticipated drilling prospects, number of pay zones,
trend potential, expected project economics and access to market. The
Company incorporates its digital database, including geophysical,
geological and production data, and the opinions of regional geologists and
geophysicists in its participation decisions. Except within areas of
mutual interest ("AMI") formed around prospects offered under the
exploration agreement with the Hughes Company, the Company is free to
acquire leases, develop its own prospects and explore in the onshore Gulf
Coast region.
TEXAS. The Company owns working interests in 34 wells in Texas that had
aggregate average production as of December 31, 1998 of 53.1 MMcfe/d gross
(4.7 MMcfe/d net to the Company) from depths ranging from 3,500 to 14,500
feet. Since the Company began its exploration in Texas in 1987, it has
participated in 300 square miles of 3-D seismic surveys and 78 wells, of
which 40 (51%) established commercial production. The Company has no
drilling activity budgeted for 1999 in the Texas Gulf Coast region. As of
December 31, 1998, the Company had established gross proved reserves of
38.4 Bcfe (3.5 Bcfe net to the Company).
LOUISIANA. The Company owns working interests in producing properties in
Cameron and Terrebonne Parish, Louisiana that had aggregate average
production as of December 31, 1998 of 4.8 MMcfe/d gross (0.6 MMcfe/d net to
the Company). Since the Company began its exploration in Louisiana in
1995, it has participated in 51 square miles of 3-D seismic surveys and 23
gross wells, nine of which were completed as commercially productive, five
of which currently are producing. The Company has budgeted two wells (0.9
net to the Company) for 1999 in the Louisiana area, with a 1999 capital
expenditure budget of approximately $0.3 million. One of the wells that is
budgeted for drilling in 1999 is in the immediate area where the Company
was in the process of completing one well (0.7 net to the Company) at
December 31, 1998. As of December 31, 1998, the Company's Louisiana wells
had established estimated gross proved reserves of 3.2 Bcfe (0.8 Bcfe net
to the Company).
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BLACKFEET INDIAN RESERVATION
In 1998, the Company entered into a joint venture program with K2
Energy Corporation ("K2") to explore on the Blackfeet Indian Reservation
(the "Reservation") located in Glacier County, Montana. At December
31,1998, the Company owned an interest in 150,000 gross leasehold acres
(75,000 net to the Company) in the Reservation. The northern boundary of the
Reservation is located approximately 25 miles south of the Waterton, Lookout
Butte and Pincher Creek Fields (Alberta, Canada), which have produced 3.8
trillion cubic feet of natural gas ("Tcf"), 0.3 Tcf and 0.5 Tcf, respectively.
The eastern boundary of the Reservation is outlined by the Cut Bank Oil Field
(Glacier County, Montana), which has produced approximately 175 million
barrels of oil ("MMBbl") and 309 Bcf of natural gas. In 1998, the Company
incurred $1.1 million in leasehold and 2-D seismic costs on this project.
MICHIGAN BASIN
The Company has been involved in oil and natural gas exploration and
production activities in the Michigan Basin since 1925. These activities
include operations in the Northern and Western Niagaran Reef Trend
(Silurian) and the Antrim Shale (Devonian) in Otsego, Montmorency and
Manistee Counties. Beginning in 1988 the Company participated in the
drilling of over 600 Antrim Shale wells. The Company currently has an
interest in over 300 Antrim Shale wells (in which it owns an average 11.9%
working interest), some of which have been assigned to third parties for
the purpose of monetizing the Section 29 tax credits available for
production from the assigned interests. The balance of the wells were sold
to fund the Company's exploration program. The majority of these Antrim
Shale wells are in Otsego County and produce from depths of approximately
1,500 to 2,500 feet.
Production from the Antrim Shale, including the Section 29 tax credits
available from such production, continues to be the Company's primary
producing property base in this region. As a result of its shallow
production in the Antrim Shale, the Company has an interest in
approximately 11,000 net acres held by production in Otsego County,
including its deep rights, primarily for the Niagaran Reef Trend located at
depths of approximately 6,500 feet. The Company has approximately 8,700
gross acres leased in Manistee County, which is expected to provide
sufficient acreage for development of a field if the drilling is deemed
economical. In 1998, the Company conducted a 10 square mile 3-D seismic
survey in Hillsdale County upon which the Company has drilled a discovery
well that has tested at sustained rates of 7.3 MMcf/d. The project is
located approximately 12 miles southwest of the Albion-Scipio Field which
has produced over 125 MMbbl of oil and 200 Bcf of natural gas. The Company
has a 100% working interest in the Manistee and Hillsdale County projects.
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JOINT VENTURE EXPLORATION, PARTICIPATION AND FARM-OUT AGREEMENTS
The Company is a party to the following joint venture exploration,
participation, farm-out and other agreements:
MISSISSIPPI SALT BASIN AGREEMENTS
Since March 1993, the Company has entered into a series of joint
venture exploration agreements and farm-out agreements with AHC, Liberty
Energy Corporation, Bonray, Inc. and Key. These agreements govern the
rights and obligations of the Company and the other working-interest owners
with respect to lease acquisition, seismic surveys, drilling and
development of specified geographic AMI's over and around 22 salt domes and
related salt structures in Southern Mississippi within the Mississippi Salt
Basin. Pursuant to these agreements, the Company has acquired and will
have the right to acquire a portion of the working interest in leases owned
or acquired by the parties within the AMIs. The agreements begin to expire
January 1, 2000, except with respect to AMIs where a joint operating
agreement has been executed, in which case the term extends as long as any
lease within that AMI remains in effect.
Under the joint venture agreement between MOC and Key, if either party
elects not to participate on a proposed 3-D seismic program proposed by the
other party, the non-participating party will farm-out its non-producing
leasehold interest in that dome, retaining an option to participate after
payout of the seismic expenses and the drilling and completion expenses of
the exploratory well, for a proportionally reduced 25% working interest in
the exploratory well. The non-participating party will retain 25% of its
original leasehold interest outside the initial well but within the
identified dome area. Without mutual agreement, no more than two 3-D
seismic surveys will be committed to and/or conducted concurrently. Either
party may propose an Initial Exploratory Well, defined as the first
exploratory well proposed and drilled on each dome after a 3-D program has
been conducted. A party electing not to participate in an Initial
Exploratory Well is obligated to assign to the proposing party its interest
in leases within that dome area to the depth drilled by the Initial
Exploratory Well. For wells drilled without conducting a 3-D survey, a
non-participating party is subject to a 400% non-consent penalty. MOC is
the operator for leasehold acquisition and production operations, and Key
is generally the operator for 3-D seismic, and operates the drilling and
completion activities on the eight domes that are jointly owned.
ONSHORE GULF COAST AGREEMENTS
MOC and the Hughes Company executed a Participation Agreement dated
January 1, 1994. Pursuant to the provisions of the Participation
Agreement, as extended for the years 1995 and 1996, MOC had the option to
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participate with Hughes for a 25% of 8/8ths working interest in prospects
offered by the Hughes Company during calendar years 1994, 1995 and 1996.
Pursuant to participation letters, MOC elected to participate in a number
of prospects including the Destino Prospect in Duval County, Texas, the
Dilworth Prospect in McMullen County, Texas, the South Aviators Prospect in
Zapata County, Texas, the McCaskill Prospect in Karnes County, Texas, the
Mirando Hondo Prospect in Webb County, Texas, the Lapeyrouse Prospect in
Terrebonne Parish, Louisiana and the Northwest Kings Bayou Prospect in
Cameron Parish, Louisiana. Each of the participation letters identifies
the prospect, county and area covered therein. The Participation Agreement
requires MOC to pay its proportionate share of actual costs, an overhead
fee, prospect bonuses and certain back-in working interests at prospect
payout and program payout. The Participation Agreement provides a form of
Joint Operating Agreement which is to be executed as to each prospect. The
Joint Operating Agreement generally provides that the Hughes Company will
be the operator, that any party may propose to drill a well or other
operation subject to limitations with respect to concurrent wells and that
parties electing not to participate in a proposed operation are subject to
a 400% non-consent penalty. MOC is entitled to the benefit of any special
marketing arrangements or price structures that the Hughes Company is able
to negotiate in regard to the sale but may elect to market its share of oil
or natural gas in kind.
BLACKFEET INDIAN RESERVATION AGREEMENTS
The Company entered into an Exploration and Development Agreement (the
"EDA") with K2 on June 17, 1998 to explore and develop approximately
291,000 gross acres on the Reservation located in Glacier County, Montana.
The EDA provides that Miller and K2 are equal partners in the K2/Blackfeet
Agreement (the "Agreement") executed between K2 and the Blackfeet Tribe
(the "Tribe") on March 9, 1998. Terms of the Agreement call for Miller/K2
to drill three gross wells (1.5 net to the Company) and pay $0.6 million
($0.3 million net to the Company) to the Tribe by May 1, 1999 for which
30,000 gross acres (15,000 net to the Company) will be earned from the
Tribe. Three gross additional wells (1.5 net to the Company) must be
drilled and $0.6 million paid ($0.3 million net to the Company) to the
Tribe each subsequent year for four years totaling 15 gross wells (7.5 net
to the Company) and $3.0 million ($1.5 million net to the Company) in
payments to the Tribe for which 150,000 gross acres (75,000 net to the
Company) will be earned. The Tribe will grant leases with a primary term
of eight years and can be held by production for 50 years and provides for
a maximum combined royalty and production tax burden of 35%.
MICHIGAN BASIN AGREEMENTS
MOC entered into a Purchase and Sale Agreement dated as of January 1,
1995 with Miller Shale Limited Partnership ("MSLP") for the purpose of
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monetizing the Section 29 tax credits available from most of its Antrim gas
wells in Michigan, and a Purchase and Sale Agreement dated as of November
1, 1996 with MSLP for the purpose of selling part of the reversionary
interest retained by MOC under the prior Purchase and Sale Agreement. MSLP
is a Michigan limited partnership owned 1% by the general partner, Miller
Shale S.V., L.L.C., an affiliate of MOC, and 99% by the limited partner,
Far Gas Acquisitions Corporation, an unrelated party. As a result,
pursuant to the terms of the two Purchase and Sale Agreements, MOC has
assigned its interest in the wells, leases, equipment and other property to
MSLP, reserving three separate production payments, an additional
contingent payment and a reversionary interest. The first and second
production payments generally entitle MOC to receive 97% of the net cash
flow from the assigned properties until a specified dollar amount or
specified volume is achieved from production attributable to the assigned
interests. As of December 31, 1998, the estimated remaining production
volume was 7.1 Bcfe, the estimated remaining dollar amount was $4.3 million
and the volumetric threshold was 4.1 Bcfe. The third production payment
and the additional contingent payment generally entitle MOC to receive 96%
of the net cash flow from additional specified volumes of production
attributable to the assigned interests. The reversionary interest entitles
MOC to a reassignment of 90% of the interests after a larger specified
volume of natural gas has been produced from the assigned interests. MSLP
also is obligated to make quarterly payments to MOC equivalent to a
percentage of the tax credits available under Section 29 with respect to
natural gas produced and sold from the interests assigned. MOC also has an
option to repurchase the assigned interests for fair market value after
December 31, 2002, the expiration date of the Section 29 tax credits.
VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth information of the Company with respect
to production volumes, average prices received and average production costs
for the periods indicated:
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YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
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Production:
Crude oil and condensate (Mbbls) . . . . . . . . 247.6 47.4 46.5
Natural gas (MMcf) . . . . . . . . . . . . . 8,953.3 2,241.2 2,030.0
Natural gas equivalent (Mmcfe) . . . . . . . . . 10,438.7 2,525.9 2,309.1
Average sales prices:
Crude oil and condensate ($ per Bbl) . . . . . . . $ 10.69 $ 20.33 $ 23.66
Natural gas ($ per Mcfe) . . . . . . . . . . . 2.05 2.60 2.77
Natural gas equivalent ($ per Mcfe) . . . . . . . 2.01 2.69 2.91
Average Costs ($ per Mcfe):
Lease operating expenses and
production taxes . . . . . . . . . . . . $ 0.32 $ 0.58 $ 0.49
Depreciation, depletion and amortization. . . . . . 1.53 1.00 1.14
General and administrative . . . . . . . . . . 0.33 0.87 0.69
OIL AND NATURAL GAS MARKETING AND MAJOR CUSTOMERS
Most of the Company's oil and natural gas production is sold under
price sensitive or spot market contracts. The revenues generated by the
Company's operations are highly dependent upon the prices of and demand for
oil and natural gas. The price received by the Company for its oil and
natural gas production depends on numerous factors beyond the Company's
control, including seasonality, the condition of the United States economy,
foreign imports, political conditions in other oil-producing and natural
gas-producing countries, the actions of the Organization of Petroleum
Exporting Countries and domestic government regulation, legislation and
policies. In 1998, decreases in the prices of oil and natural gas had an
adverse effect on the carrying value of the Company's proved reserves and
the Company's revenues, profitability and cash flow. Although the Company
currently is not experiencing any significant involuntary curtailment of
its oil or natural gas production, market, economic and regulatory factors
in the future may materially affect the Company's ability to sell its oil
or natural gas production. For the year ended December 31, 1998, sales to
the Company's four largest customers were approximately 50%, 21%, 12% and
7%, respectively, of the Company's oil and natural gas revenues. Due to
the availability of other markets and pipeline connections, the Company
does not believe that the loss of any single oil or natural gas customer
would have a material adverse effect on the Company's results of operations
or financial condition.
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COMPETITION
The oil and gas industry is highly competitive in all of its phases.
The Company encounters competition from other oil and natural gas companies
in all areas of its operations, including the acquisition of seismic
options and lease options on properties. The Company's competitors include
major integrated oil and natural gas companies and numerous independent oil
and natural gas companies, individuals and drilling and income programs.
Many of the Company's competitors are large, well established companies
with substantially larger operating staffs and greater capital resources
than the Company's and which, in many instances, have been engaged in the
exploration and production business for a much longer time than the
Company. Such companies may be able to pay more for seismic and lease
options on oil and natural gas properties and exploratory prospects and to
define, evaluate, bid for and purchase a greater number of properties and
prospects than the Company's financial or human resources permit. The
Company's ability to explore for oil and natural gas prospects, to acquire
additional properties and to discover reserves in the future will depend
upon its ability to conduct its operations, to evaluate and select suitable
properties and to consummate transactions in a highly competitive
environment.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
gas industry. As is customary in the industry in the case of undeveloped
properties, little investigation of record title is made at the time of
acquisition (other than a preliminary review of local records).
Investigations, including a title opinion of legal counsel, generally are
made before commencement of drilling operations. To the extent title
opinions or other investigations reflect title defects, the Company, rather
than the seller of undeveloped property, typically is responsible to cure
any such title defects at the Company's expense. If the Company were
unable to remedy or cure title defect of a nature such that it would not be
prudent to commence drilling operations on the property, the Company could
suffer a loss of its entire investment in such property. The Company's
properties are subject to customary royalty, overriding royalty, carried,
net profits, working and other similar interests, liens incident to
operating agreements, liens for current taxes and other burdens. In
addition, the Company's credit facility is secured by certain oil and
natural gas interests and other properties of the Company.
SECTION 29 TAX CREDIT
The natural gas production from wells drilled on certain of the
Company's properties in Otsego and Montmorency Counties, Michigan qualifies
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for the Section 29 tax credit. The Section 29 tax credit is an income tax
credit against regular federal income tax liability with respect to sales
of the Company's production of natural gas produced from tight gas sand
formations, subject to a number of limitations. Fuels qualifying for the
Section 29 tax credit must be produced from a well drilled or a facility
placed in service after November 5, 1990 and before January1, 1993, and be
sold before January 1, 2003.
The basic credit, which currently is approximately $1.07 per million
british thermal units ("MMBtu") of natural gas produced from Antrim Shale,
is computed by reference to the price of crude oil and is phased out as the
price of oil exceeds $23.50 in 1979 dollars (as adjusted for inflation)
with complete phaseout if such price exceeds $29.50 in 1979 dollars (as
adjusted for inflation). Under this formula, the commencement of phaseout
would be triggered if the average price for crude oil rose above
approximately $48.00 per Bbl in current dollars. The Company generated
approximately $0.2 million of Section 29 tax credits in 1998. The Section
29 tax credit may not be credited against the alternative minimum tax, but
under certain circumstances may be carried over and applied against regular
tax liability in future years. Therefore, no assurances can be given that
the Company's Section 29 tax credits will reduce its federal income tax
liability in any particular year.
MISSISSIPPI TAX ABATEMENT
The State of Mississippi currently has a production tax abatement
program that exempts certain oil and natural gas production from state
severance taxes. The exemption as it relates to the Company applies to
discovery wells and wells developed as a result of 3-D seismic surveys.
The exemption is phased out if the sales price for oil exceeds $25.00 per
Bbl or $3.50 per Mcf. The applicable production is exempt for up to five
years and expires June 30, 1999. A bill to extend this abatement currently
is being considered by the Mississippi State Legislature.
LOUISIANA TAX ABATEMENT
The State of Louisiana provides for an exemption from production taxes
for up to two years or until the well reaches payout (as defined by the
State of Louisiana's Department of Revenue and Taxation) and generally
applies to horizontal wells and to vertical wells over 15,000 feet. The
State of Louisiana also provides an exemption for discovery wells completed
between September 30, 1994 and September 30, 1996, which lasts for two
years or until the well reaches payout.
GOVERNMENTAL REGULATION
The Company's oil and natural gas exploration, production and related
operations are subject to extensive rules and regulations promulgated by
-12-
federal, state and local agencies. Failure to comply with such rules and
regulations can result in substantial penalties. The regulatory burden on
the oil and gas industry increases the Company's cost of doing business and
affects its profitability. Although the Company believes it is in
substantial compliance with all applicable laws and regulations, the
Company is unable to predict the future cost or impact of complying with
such laws because those laws and regulations frequently are amended or
reinterpreted.
STATE REGULATION
The states in which the Company operates require permits for drilling
operations, drilling bonds and reports concerning operations and impose
other requirements relating to the exploration and production of oil and
natural gas. These states also have statutes or regulations addressing
conservation matters, including provisions for the unitization or pooling
of oil and natural gas properties, the establishment of maximum rates of
production from wells and the regulation of spacing, plugging and
abandonment of such wells. In addition, state laws generally prohibit the
venting or flaring of natural gas, regulate the disposal of fluids used in
connection with operations and impose certain requirements regarding the
ratability of production.
FEDERAL REGULATION
The Company's sales of natural gas are affected by the availability,
terms and cost of transportation. The price and terms for access to
pipeline transportation are subject to extensive regulation. The Federal
Energy Regulatory Commission ("FERC") regulates the transportation and sale
of natural gas in interstate commerce pursuant to the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. In the past, the federal
government has regulated the prices at which oil and natural gas can be
sold. While sales by producers of natural gas and all sales of oil and
natural gas liquids currently can be made at uncontrolled market prices,
Congress could reenact price controls in the future.
In recent years, FERC has undertaken various initiatives to increase
competition within the natural gas industry. As a result of initiatives
like FERC Order 636, issued in April 1992 and its progeny, the interstate
natural gas transportation and marketing system has been substantially
restructured to remove various barriers and practices that historically
limited non-pipeline natural gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local
distribution companies and large industrial and commercial customers. The
most significant provisions of Order No. 636 require that interstate
pipelines provide transportation separate or "unbundled" from their sales
service, and require that pipelines provide firm and interruptible
-13-
transportation service on an open access basis that is equal for all
natural gas supplies. In many instances, the result of Order No. 636 and
related initiatives has been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. Although
Order No. 636 largely has been upheld on appeal, several appeals remain
pending in related restructuring proceedings. It is difficult to predict
when these remaining appeals will be completed or their impact on the
Company.
FERC has announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-
service ratemaking methodology to establish the rates interstate pipelines
may charge for their services. A number of pipelines have obtained FERC
authorization to charge negotiated rates as one such alternative. In
February 1997, FERC announced a broad inquiry into issues facing the
natural gas industry to assist FERC in establishing regulatory goals and
priorities in the post-Order No. 636 environment. Similarly, the Texas
Railroad Commission recently has changed its regulations governing
transportation and gathering services provided by intrastate pipelines and
gatherers to prohibit undue discrimination in favor of affiliates. While
the changes being considered by these federal and state regulators would
affect the Company only indirectly, they are intended to further enhance
competition in natural gas markets. Additional proposals and proceedings
that might affect the natural gas industry are pending before Congress,
FERC, state commissions and the courts. The natural gas industry
historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by
FERC and Congress will continue.
The price the Company receives from the sale of oil and natural gas
liquids is affected by the cost of transporting products to markets.
Effective January 1, 1995, FERC implemented regulations establishing an
indexing system for transportation rates for oil pipelines, which,
generally, would index such rates to inflation, subject to certain
conditions and limitations. The Company is not able to predict with
certainty the effect, if any, of these regulations on its operations.
However, the regulations may increase transportation costs or reduce well
head prices for oil and natural gas liquids.
ENVIRONMENTAL MATTERS
The Company's operations and properties are subject to extensive and
changing federal, state and local laws and regulations relating to
environmental protection, including the generation, storage, handling,
emission, transportation and discharge of materials into the environment,
-14-
and relating to safety and health. The recent trend in environmental
legislation and regulation generally is toward stricter standards, and this
trend likely will continue. These laws and regulations may require the
acquisition of a permit or other authorization before construction or
drilling commences; restrict the types, quantities and concentration of
various substances that can be released into the environment in connection
with drilling and production activities; limit or prohibit construction,
drilling and other activities on certain lands lying within wilderness,
wetlands and other protected areas; require remedial measures to mitigate
pollution from former operations such as plugging abandoned wells; and
impose substantial liabilities for pollution resulting from the Company's
operations. The permits required for various of the Company's operations
are subject to revocation, modification and renewal by issuing authorities.
Governmental authorities have the power to enforce compliance with their
regulations, and violators are subject to civil and criminal penalties or
injunction. Management believes that the Company is in substantial
compliance with current applicable environmental laws and regulations, and
that the Company has no material commitments for capital expenditures to
comply with existing environmental requirements. Nevertheless, changes in
existing environmental laws and regulations or in interpretations thereof
could have a significant impact on the Company, as well as the oil and gas
industry in general and thus the Company is unable to predict the ultimate
costs and effects of such continued compliance in the future.
The Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA") and comparable state statutes impose strict, joint and
several liability on certain classes of persons who are considered to have
contributed to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of a disposal site or sites
where a release occurred and companies that disposed or arranged for the
disposal of the hazardous substances released at the site. Under CERCLA
such persons or companies may be liable for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for the neighboring
land owners and other third parties to file claims for personal injury,
property damage and recovery of response costs allegedly caused by the
hazardous substances released into the environment. The Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes govern
the disposal of "solid waste" and "hazardous waste" and authorize
imposition of substantial civil and criminal penalties for noncompliance.
Although CERCLA currently excludes petroleum from its definition of
"hazardous substance," state laws affecting the Company's operations impose
clean-up liability relating to petroleum and petroleum-related products.
In addition, although RCRA classifies certain oil field wastes as "non-
hazardous," such exploration and production wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent
handling and disposal requirements.
-15-
The Company has acquired leasehold interests in numerous properties
that for many years have produced oil and natural gas. Although the
Company believes that the previous owners of these interests used operating
and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or
under the properties. In addition, most of the Company's properties are
operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes is not under the Company's control. These
properties and the wastes disposed thereon may be subject to CERCLA, RCRA
and analogous state laws. Notwithstanding the Company's lack of control
over properties operated by others, the failure of the operator to comply
with applicable environmental regulations may, in certain circumstances,
adversely impact the Company.
Federal regulations require certain owners or operators of facilities
that store or otherwise handle oil, such as the Company, to prepare and
implement spill prevention, control countermeasure and response plans
relating to the possible discharge of oil into surface waters. The Oil
Pollution Act of 1990, as amended ("OPA"), contains numerous requirements
relating to the prevention of and response to oil spills into waters of the
United States. For onshore facilities that may affect waters of the United
States, OPA requires an operator to demonstrate $10.0 million in financial
responsibility, and for offshore facilities the financial responsibility
requirement is at least $35.0 million. Regulations currently are being
developed under federal and state laws concerning oil pollution prevention
and other matters that may impose additional regulatory burdens on the
Company. In addition, the federal Clean Water Act and analogous state laws
require permits to be obtained to authorize discharge into surface waters
or to construct facilities in wetland areas. With respect to certain of
its operations, the Company is required to maintain such permits or meet
general permit requirements. The Environmental Protection Agency ("EPA")
has adopted regulations concerning discharges of storm water runoff. This
program requires covered facilities to obtain individual permits,
participate in a group or seek coverage under an EPA general permit. The
Company believes that it will be able to obtain, or be included under, such
permits, where necessary, and to make minor modifications to existing
facilities and operations that would not have a material effect on the
Company.
EMPLOYEES
As of April 13, 1999, the Company had 33 full-time employees,
including four geologists, two geophysicists and two engineers. None of
the Company's employees are represented by any labor union. The Company
believes its relations with its employees are good. To optimize prospect
generation and development, the Company uses the services of independent
consultants and contractors to perform various professional services,
-16-
particularly in the area of seismic data mapping, acquisition leases and
lease options, construction, design, well-site surveillance, permitting and
environmental assessment. Field and on-site productions operation
services, such as pumping, maintenance, dispatching, inspection and
testing, generally are provided by independent contractors. The Company
believes that this use of third-party service providers enhances its
ability to contain general and administrative expenses.
DEPENDENCE ON EXPLORATORY DRILLING ACTIVITIES
The Company's revenues, operating results and future rate of growth
are substantially dependent upon the success of its exploratory drilling
program. Exploratory drilling involves numerous risks, including the risk
that no commercially productive oil or natural gas reservoirs will be
encountered. The cost of drilling, completing and operating wells is often
uncertain, and drilling operations may be curtailed, delayed or canceled as
a result of a variety of factors, including unexpected drilling conditions,
pressure or irregularities in formations, equipment failures or accidents,
adverse weather conditions, compliance with governmental requirements and
shortages or delays in the availability of drilling rigs and the delivery
of equipment. Despite the use of 2-D and 3-D seismic data and other
advanced technologies, exploratory drilling remains a speculative activity.
Even when fully utilized and properly interpreted, 2-D and 3-D seismic data
and other advanced technologies only assist geoscientists in identifying
subsurface structures and do not enable the interpreter to know whether
hydrocarbons are in fact present in those structures. In addition, the use
of 2-D and 3-D seismic data and other advanced technologies requires
greater pre-drilling expenditures than traditional drilling strategies, and
the Company could incur losses as a result of such expenditures. The
Company's future drilling activities may not be successful. There can be
no assurance that the Company's overall drilling success rate or its
drilling success rate for activity within a particular region will not
decline. Unsuccessful drilling activities could have a material adverse
effect on the Company's business, results of operations and financial
condition.
The Company may not have any option or lease rights in potential
drilling locations it identifies. Although the Company has identified
numerous potential drilling locations, there can be no assurance that they
will ever be leased or drilled or that oil or natural gas will be produced
from these or any other potential drilling locations. In addition,
drilling locations initially may be identified through a number of methods,
some of which do not include interpretation of 3-D or other seismic data.
Wells that currently are included in the Company's capital budget may be
based upon statistical results of drilling activities in other areas that
the Company believes are geologically similar, rather than on analysis of
seismic or other data. Actual drilling results are likely to vary from
-17-
such statistical results, and such variance may be material. Similarly,
the Company's drilling schedule may vary from its capital budget, and there
is increased risk of such variance from the 1999 capital budget because of
future uncertainties, including those described above. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
OPERATING HAZARDS AND UNINSURED RISKS
Drilling activities are subject to many risks, including the risk that
no commercially productive reservoirs will be encountered. There can be no
assurance that new wells drilled by the Company will be productive or that
the Company will recover all or any portion of its investment. Drilling
for oil and natural gas may involve unprofitable efforts, not only from dry
wells, but from wells that are productive but do not produce sufficient net
revenues to return a profit after drilling, operating and other costs. The
cost of drilling, completing and operating wells is often uncertain. The
Company's drilling operations may be curtailed, delayed or canceled as a
result of numerous factors, many of which are beyond the Company's control,
including title problems, weather conditions, compliance with governmental
requirements and shortages or delays in the delivery of equipment and
services. The Company's future drilling activities may not be successful
and, if unsuccessful, such failure may have a material adverse effect on
the Company's future results of operations and financial condition.
In addition, the Company's use of 3-D seismic technology requires
greater pre-drilling expenditures than traditional drilling strategies.
Although the Company believes that its use of 3-D seismic technology will
increase the probability of success, unsuccessful wells are likely to
occur. There can be no assurance that the Company's drilling program will
be successful or that unsuccessful drilling efforts will not have a
material adverse effect on the Company.
The Company's operations are subject to hazards and risks inherent in
drilling for and producing and transporting oil and natural gas, such as
fires, natural disasters, explosions, encountering formations with abnormal
pressures, blowouts, craterings, pipeline ruptures and spills,
uncontrollable flows of oil, natural gas or well fluids, any of which can
result in the loss of hydrocarbons, environmental pollution, personal
injury claims and other damage to properties of the Company and others.
The Company maintains insurance against some but not all of the risks
described above. In particular, the insurance maintained by the Company
does not cover claims relating to failure of title to oil and natural gas
leases, trespass during 2-D and 3-D survey acquisition or surface change
attributable to seismic operations and, except in limited circumstances,
losses due to business interruption. The Company may elect to self-insure
if management believes that the cost of insurance, although available, is
excessive relative to the risks presented. In addition, pollution and
-18-
environmental risks generally are not fully insurable. The Company
participates in a substantial percentage of its wells on a non-operated
basis, which may limit the Company's ability to control the risks
associated with oil and natural gas operations. The occurrence of an event
that is not covered, or not fully covered, by insurance could have a
material adverse effect on the Company's business, financial condition and
results of operations.
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Company's revenues, operating results and future rate of growth
are substantially dependent upon the prevailing prices of, and demand for,
oil and natural gas. Historically, the markets for oil and natural gas
have been volatile and are likely to continue to be volatile in the future.
Prices for oil and natural gas are subject to wide fluctuation in response
to relatively minor changes in the supply of and demand for oil and natural
gas, market uncertainty and a variety of additional factors that are beyond
the control of the Company. These factors include worldwide and domestic
supplies of oil and natural gas, the ability of the members of the
Organization of Petroleum Exporting Countries to agree to and maintain oil
price and production controls, political instability or armed conflict in
oil-producing regions, the price and level of foreign imports, the level of
consumer demand, the price and availability of alternative fuels, the
availability of pipeline capacity, weather conditions, domestic and foreign
governmental regulations and taxes and the overall economic environment.
It is impossible to predict future oil and natural gas price movements with
certainty. A continuation of the significantly lower oil and gas prices
experienced in 1998, as compared to prior years, or a further decline in
oil and natural gas prices will likely have a material adverse effect on
the Company's financial condition, liquidity, ability to finance planned
capital expenditures and results of operations. Lower oil and natural gas
prices also may reduce the amount of oil and natural gas that the Company
can produce economically.
The Company periodically reviews the carry value of its oil and
natural gas properties under the full cost accounting rules of the
Securities and Exchange Commission ("SEC"). Under these rules, capitalized
costs of proved oil and natural gas properties may not exceed the present
value of estimated future net revenues from proved reserves, discounted at
10% and the lower of cost or market value of unproved properties.
Application of the "ceiling" test generally requires pricing future revenue
at the unescalated prices in effect as of the end of each fiscal quarter
and requires a writedown for accounting purposes if the ceiling is
exceeded, even if prices were depressed for only a short period of time.
The Company may be required to writedown the carrying value of its oil and
natural gas properties when oil and natural gas prices are depressed or
unusually volatile. If a writedown is required, it would result in a
-19-
charge to earnings, but would not impact cash flow from operating
activities. Once incurred, a writedown of oil and natural gas properties
is not reversible at a later date.
RISKS ASSOCIATED WITH MANAGEMENT OF GROWTH AND IMPLEMENTATION OF GROWTH
STRATEGY
Any increase in the Company's activities as an operator will increase
its exposure to operating hazards. The Company has relied in the past and
expects to continue to rely on project partners and independent
contractors, including geologists, geophysicists and engineers, that have
provided the Company with seismic survey planning and management, project
and prospect generation, land acquisition, drilling and other services.
Due to the competitive nature of the markets in which the Company operates,
the Company currently believes that the demand for qualified geologists,
geophysicists and engineers is increasing. As the Company increases the
number of projects it is evaluating or in which it is participating, there
will be additional demands on the Company's financial, technical,
operational and administrative resources and continued reliance by the
Company on project partners and independent contractors, and these strains
on resources, additional demands and continued reliance may negatively
affect the Company. The Company's ability to continue its growth will
depend upon a number of factors, including its ability to obtain leases or
options on properties, its ability to acquire additional 3-D seismic data,
its ability to identify and acquire new exploratory sites, its ability to
develop existing sites, its ability to continue to retain and attract
skilled personnel, its ability to maintain or enter into new relationships
with project partners and independent contractors, the results of its
drilling program, hydrocarbon prices, access to capital and other factors.
Although the Company intends to upgrade its technical, operational and
administrative resources and to increase its ability to provide internally
certain of the services previously provided by outside sources, there can
be no assurance that it will be successful in doing so or that it will be
able to continue to maintain or enter into new relationships with project
partners and independent contractors. The failure to continue to upgrade
the Company's technical, administrative, operating and financial resources
and control systems or the occurrence of unexpected expansion difficulties,
including difficulties in recruiting or engaging and retaining
geophysicists, geologists, engineers and sufficient numbers of qualified
personnel and independent contractors to enable the Company to expand its
role in the drilling and production phase, or the reduced availability of
seismic gathering, drilling or other services in the fact of growing
demand, could have a material adverse effect on the Company's business,
financial condition and results of operations. There can be no assurance
that the Company will be successful in achieving growth or any other aspect
of its business strategy.
-20-
RESERVE REPLACEMENT RISK
In general, production from oil and natural gas properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. Except to the extent that the Company conducts successful
exploration and development activities or acquires properties containing
proved reserves, or both, the proved reserves of the Company will decline
as reserves are produced. The Company's future oil and natural gas
production is highly dependent upon its ability to economically find,
develop or acquire reserves in commercial quantities. The business of
exploring for or developing reserves is capital intensive. To the extent
cash flow from operations is reduced and external sources of capital become
limited or unavailable, the Company's ability to make the necessary capital
investment to maintain or expand its asset base of oil and natural gas
reserves would be impaired. The Company participates in a substantial
percentage of its wells as non-operator. The failure of an operator of the
Company's wells to adequately perform operations, or an operator's breach
of the applicable agreements, could adversely impact the Company. In
addition, there can be no assurance that the Company's future exploration
and development activities will result in additional proved reserves or
that the Company will be able to drill productive wells at acceptable
costs. Furthermore, although the Company's revenues could increase if
prevailing prices for oil and natural gas increase significantly, the
Company's finding and development costs also could increase.
MARKETABILITY OF PRODUCTION
The marketability of the Company's production depends in part upon the
availability, proximity and capacity of natural gas gathering systems,
pipelines and processing facilities. The Company delivers natural gas
through gas gathering systems and gas pipelines that it does not own.
Federal and state regulation of oil and natural gas production and
transportation, tax and energy policies, changes in supply and demand and
general economic conditions all could adversely affect the Company's
ability to produce and market its oil and natural gas. Any dramatic change
in market factors could have a material adverse effect on the Company's
business, financial condition and results of operations.
DEPENDENCE ON KEY PERSONNEL
The Company has assembled a team of geologists, geophysicists and
engineers, some of whom are non-employee consultants and independent
contractors, having considerable experience in oil and natural gas
exploration and production, including applying 2-D and 3-D imaging
technology. The Company is dependent upon the knowledge, skills and
experience of these experts to provide 2-D and 3-D imaging and to assist
the Company in reducing the risks associated with its participation in oil
-21-
and natural gas exploration projects. In addition, the success of the
Company's business also depends to a significant extent upon the abilities
and continued efforts of its management. The Company does not maintain
key-man life insurance with respect to any of its employees. The loss of
services of key management personnel or the Company's technical experts and
consultants, or the inability to attract additional qualified personnel,
experts or consultants, could have a material adverse effect on the
Company's business, financial condition, results of operations, development
efforts and ability to grow. There can be no assurance that the Company
will be successful in attracting and/or retaining its key management
personnel or technical experts or consultants.
TECHNOLOGICAL CHANGES
The oil and gas industry is characterized by rapid and significant
technological advancements and introductions of new products and services
utilizing new technologies. As others use or develop new technologies, the
Company may be placed at a competitive disadvantage, and competitive
pressures may force the Company to implement such new technologies at
substantial costs. In addition, other oil and gas companies may have
greater financial, technical and personnel resources that allow them to
enjoy technological advantages and may in the future allow them to
implement new technologies before the Company. There can be no assurance
that the Company will be able to respond to such competitive pressures and
implement such technologies on a timely basis or at an acceptable cost.
One or more of the technologies currently utilized by the Company or
implemented in the future may become obsolete. In such cases, the
Company's business, financial condition and results of operations could be
materially adversely affected. If the Company is unable to utilize the
most advanced commercially available technology, the Company's business,
financial condition and results of operations could be materially and
adversely affected.
SUBSTANTIAL CAPITAL PROJECTS
The Company makes and will continue to make substantial capital
expenditures in its exploration and development projects. The Company
intends to finance these capital expenditures with cash flow from
operations. Additional financing may be required in the future to fund the
Company's developmental and exploratory drilling and seismic activities.
No assurance can be given as to the availability or terms of any such
additional financing that may be required or that financing will continue
to be available under the existing or new financing arrangements. If
additional capital sources are not available to the Company, its drilling,
seismic and other activities may be curtailed and its business, financial
conditions and results of operations could be materially adversely
affected.
-22-
CONTROL BY CERTAIN STOCKHOLDERS
As of December 31, 1998, the Company's directors, executive officers
and certain of their affiliates, beneficially owned approximately 44.8% of
the Company's outstanding Common Stock. Accordingly, these stockholders, as
a group, will be able to control the outcome of stockholder votes, including
votes concerning the election of directors, the adoption or amendment of
provisions in the Company's Certificate of Incorporation or Bylaws and the
approval of mergers or other significant corporate transactions. The
existence of these levels of ownership concentrated in a few persons makes
it unlikely that any other holder of Common Stock will be able to affect
the management or direction of the Company. These factors also may have
the effect of delaying or preventing a change in the management or voting
control of the Company.
CERTAIN ANTITAKEOVER CONSIDERATIONS
The Company's Certificate of Incorporation and Bylaws include certain
provisions that may have the effect of delaying, deterring or preventing a
future takeover or change in control of the Company without the approval of
the Company's Board of Directors. Such provisions also may render the
removal of directors and management more difficult. Among other things, the
Company's Certificate of Incorporation and/or Bylaws: (i) provide for a
classified Board of Directors serving staggered three-year terms; (ii)
impose restrictions on who may call a special meeting of stockholders;
(iii) include a requirement that stockholder action be taken only by
unanimous written consent or at stockholder meetings; (iv) specify certain
advance notice requirements for stockholder nominations of candidates for
election to the Board of Directors and certain other stockholder proposals;
and (v) impose certain restrictions and supermajority voting requirements
in connection with specified business combinations not approved in advance
by the Company's Board of Directors. In addition, the Company's Board of
Directors, without further action by the stockholders, may cause the
Company to issue up to 2.0 million shares of preferred stock, $0.01 par
value ("Preferred Stock"), on such terms and with such rights, preferences
and designations as the Board of Directors may determine. Issuance of such
Preferred Stock, depending upon the rights, preferences and designations
thereof, may have the effect of delaying, deterring or preventing a change
in control of the Company. Further, certain provisions of the Delaware
General Corporation Law (the "Delaware Law") impose restrictions on the
ability of a third party to effect a change in control and may be
considered disadvantageous by a stockholder.
-23-
ITEM 2. PROPERTIES.
OIL AND NATURAL GAS RESERVES
The Company's estimated total proved reserves of oil and natural gas
as of December 31, 1998 and 1997, and the present values of estimated
future net revenues attributable to these reserves as of those dates were
as follows:
AS OF DECEMBER 31,
-------------------------
1998 1997
-------- --------
(Dollars in thousands,
except per unit data)
Net Proved Reserves:
Crude oil (Mbbl) . . . . . . . . . . . . . . . . . 991.7 768.5
Natural gas (MMcf) . . . . . . . . . . . . . . . . 28,921.9 17,615.1
Natural gas equivalent (MMcfe) . . . . . . . . . . . . 34,872.1 22,226.0
Net Proved Developed Reserves:
Crude oil (Mbbl) . . . . . . . . . . . . . . . . . 991.7 130.2
Natural gas (MMcf) . . . . . . . . . . . . . . . . 28,641.6 13,964.4
Natural gas equivalent (MMcfe) . . . . . . . . . . . . 34,591.8 14,745.6
Estimated future net revenues before income taxes<F1>. . . . . . $ 44,513 $ 30,505
Present value of estimated future net revenues before income taxes<F2> $ 36,425 $ 19,934
Standardized measure of discounted estimated future net cash flows<F3> $ 36,425 $ 19,334
- ---------------------
<FN>
<F1> The average prices for crude oil were $8.85 per Bbl at December 31,
1998 and $17.67 per Bbl at December 31, 1997. The average prices for
natural gas were $2.01 per Mcf (as adjusted for the effect of hedging)
at December 31, 1998 and $2.26 per Mcf at December 31, 1997.
<F2> The present value of estimated future net revenues attributable to the
Company's reserves was prepared using constant prices as of the
calculation date, discounted at 10% per annum on a pre-tax basis.
-24-
<F3> The standardized measure of discounted estimated future net cash flows
represents discounted estimated future net cash flows attributable to
the Company's reserves after income taxes, calculated in accordance
with Statement of Financial Accounting Standards ("SFAS") No. 69. The
1998 balance is not reduced by income taxes due to the tax basis of
the properties and a net operating loss carryforward. The 1997
balance does not include income taxes, as the Company was not subject
to federal income taxes until consummation of the Offering.
</FN>
The reserve estimates reflected above were prepared by S.A. Holditch &
Associates (as to Michigan Basin Antrim Shale reserves) and Miller and
Lents, Ltd. (as to non-Michigan Basin Antrim Shale reserves), independent
petroleum engineers, and are part of their reserve reports on the Company's
oil and natural gas properties.
In accordance with applicable requirements of the SEC, estimates of
the Company's proved reserves and future net revenues are made using sales
prices estimated to be in effect as of the date of such reserve estimates
and are held constant throughout the life of the properties (except to the
extent a contract specifically provides for escalation). Estimated
quantities of proved reserves and future net revenues therefrom are
affected by oil and natural gas prices, which have fluctuated widely in
recent years. There are numerous uncertainties inherent in estimating oil
and natural gas reserves and their estimated values, including many factors
beyond the control of the Company. The reserve data set forth in this Form
10-K represents only estimates. Reservoir engineering is a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact manner. The accuracy of any reserve
estimate is a function of the quality of available data and of engineering
and geologic interpretation and judgment. As a result, estimates of
different engineers, including those used by the Company, may vary. In
addition, estimates of reserves are subject to revision based upon actual
production, results of future development and exploration activities,
prevailing oil and natural gas prices, operating costs and other factors.
The revisions may be material. Accordingly, reserve estimates often are
different from the quantities of oil and natural gas that ultimately are
recovered and are highly dependent upon the accuracy of the assumptions
upon which they are based. The Company's estimated proved reserves have
not been filed with or included in reports to any federal agency.
Estimates with respect to proved reserves that may be developed and
produced in the future often are based upon volumetric calculations and
upon analogy to similar types of reserves rather than actual production
history. Estimates based on these methods generally are less reliable than
-25-
those based on actual production history. Subsequent evaluation of the
same reserves based upon production history will result in variations in
the estimated reserves and the variations may be substantial.
DRILLING ACTIVITIES
The Company drilled, or participated in the drilling of, the following
number of wells during the periods indicated:
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1998 1997 1996
--------------- -------------- ----------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Exploratory Wells:
Oil. . . . . . . . . . . 1 0.2 2 0.3 -- --
Natural gas . . . . . . . . 8 2.6 2 0.6 4 0.8
Non-productive . . . . . . . 18 8.6 8 1.8 13 6.4
--- ---- --- ---- --- ---
Total . . . . . . . . . 27 11.4 12 2.7 17 7.2
=== ==== === ==== === ===
Development Wells<F1>:
Oil. . . . . . . . . . . 4 0.8 3 0.6 6 1.2
Natural gas . . . . . . . . -- -- 11 2.3 -- --
Non-productive . . . . . . . 2 1.8 5 1.0 2 0.4
--- ---- --- ---- --- ---
Total . . . . . . . . . 6 2.6 19 3.9 8 1.6
=== ==== === ==== === ===
________________
<FN>
<F1> Includes nine gross Antrim Shale wells (1.3 net to the Company) for
the year ended December 31, 1997.
</FN>
At December 31, 1998, the Company was in the process of drilling
and/or completing four gross wells (3.0 net to the Company) that are not
reflected in the table.
-26-
PRODUCTIVE WELLS AND ACREAGE
PRODUCTIVE WELLS
The following table sets forth the Company's ownership interest as of
December 31, 1998 in productive oil and natural gas wells in the areas
indicated:
REGION OIL NATURAL GAS TOTAL
------ -------------- -------------- -------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Mississippi Salt Basin . . . . . . 1 .2 11 8.6 12 8.8
Onshore Gulf Coast
Texas . . . . . . . . . . 17 3.3 17 4.3 34 7.6
Louisiana . . . . . . . . . 1 .2 4 .6 5 .8
Michigan Basin/Other. . . . . . . 1 .1 308 37.5 309 37.6
--- ---- ---- ----- ---- -----
Total . . . . . . . . . 20 3.8 340 51.0 360 54.8
=== ==== ==== ===== ==== =====
Productive wells consist of producing wells and wells capable of
production, including wells waiting on pipeline connection. Wells that are
completed in more than one producing horizon are counted as one well. Of
the gross wells reported above, none had multiple completions.
ACREAGE
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil and natural gas, regardless of whether such
acreage contains proved reserves. A gross acre is an acre in which an
interest is owned. A net acre is deemed to exist when the sum of
fractional ownership interests in gross acres equals one. The number of
net acres is the sum of the fractional interests owned in gross acres
expressed as whole numbers and fractions thereof. The following table sets
forth the approximate developed and undeveloped acreage in which the
Company held a leasehold mineral or other interest at December 31, 1998:
-27-
REGION DEVELOPED UNDEVELOPED TOTAL
------ --------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
Mississippi Salt Basin . . . . . . 5,880 4,162 72,365 45,867 78,245 50,029
Montana . . . . . . . . . . . -- -- 150,000 75,000 150,000 75,000
Onshore Gulf Coast
Texas . . . . . . . . . . 16,125 647 7,029 2,845 23,154 3,492
Louisiana. . . . . . . . . 844 114 9,148 2,016 9,992 2,130
Michigan Basin/Other. . . . . . . 5,453 10,851 18,444 9,352 43,897 20,243
------ ------ ------- ------- ------- -------
Total . . . . . . . . . 48,302 15,774 256,986 135,120 305,288 150,894
====== ====== ======= ======= ======= =======
All of the leases for the undeveloped acreage summarized in the
preceding table will expire at the end of their respective primary terms
unless the existing leases are renewed or production has been obtained from
the acreage subject to the lease before that date, in which event the lease
will remain in effect until the cessation of production. To this end, the
Company's forecasted drilling schedule takes into consideration not only
the attractiveness of individual prospects, but the lease expirations as
well. The following table sets forth the minimum remaining terms of leases
for the total gross and net acreage at December 31, 1998:
ACRES EXPIRING
----------------------
GROSS NET
------- -------
Twelve Months Ending:
December 31, 1999 . . . . . . . . . . . 11,151 6,463
December 31, 2000 . . . . . . . . . . . 33,488 12,211
December 31, 2001 . . . . . . . . . . . 17,437 10,312
Thereafter . . . . . . . . . . . 243,212 121,908
------- -------
Total . . . . . . . . . . . . . 305,288 150,894
======= =======
-28-
FACILITIES
The Company currently leases approximately 10,500 square feet of
office space for its principal offices in Traverse City, Michigan. The
Company also leases approximately 5,200 square feet of office space in
Houston, Texas, approximately 3,500 square feet of office space in Jackson,
Mississippi and approximately 2,000 square feet of office space and 3,600
square feet of warehouse space in Columbia, Mississippi.
ITEM 3. LEGAL PROCEEDINGS.
The Company is not currently named as a defendant in any lawsuits
and/or administrative proceedings arising other than in the ordinary course
of business.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
During the fourth quarter of 1998, no matter was submitted to a vote
of security holders, through the solicitation of proxies or otherwise.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The Company's Common Stock is traded on The Nasdaq Stock Market under
the symbol "MEXP."
As of April 15, 1999, the Company estimates that there were
approximately 2,241 beneficial holders of its Common Stock. The Company
consummated the Offering on February 9, 1998. Before that time, there was
no public market for the Company's Common Stock.
The following table sets forth the high and low sales prices for the
Company's Common Stock for the periods indicated, all as reported by The
Nasdaq Stock Market:
HIGH LOW
---- ---
Year Ended December 31, 1998:
First Quarter . . . . . . . . . . . . . $10-1/4 $7-3/4
Second Quarter . . . . . . . . . . . . . 10-7/8 7-1/4
Third Quarter . . . . . . . . . . . . . 8 4-5/8
Fourth Quarter . . . . . . . . . . . . . 7-3/8 3-3/4
-29-
The Company has not in the past, and does not intend to pay cash
dividends on its Common Stock in the foreseeable future. The Company
currently intends to retain earnings, if any, for the future operation and
development of its business. The Company has entered into a credit
facility that contains provisions that may have the effect of limiting or
prohibiting the payment of dividends.
ITEM 6. SELECTED FINANCIAL DATA.
The following table presents selected historical consolidated
financial data of the Company as of the dates and for the periods
indicated. The historical consolidated financial data as of and for each
of the five years in the period ended December 31, 1998 is derived from the
consolidated financial statements which have been audited by Arthur
Andersen LLP, independent public accountants. Earnings per share has been
omitted for all periods prior to 1998 since such information is not
meaningful and the historically combined Company (prior to the Combination
Transaction) was not a separate legal entity with a single capital
structure. The following data should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements.
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In thousands, except per share data)
Statement of Operations Data:
Revenues:
Natural gas . . . . . . . . . . . $ 18,336 $5,819 $5,614 $2,748 $2,424
Crude oil and condensate. . . . . . . 2,646 964 1,101 715 672
Other operating revenues. . . . . . . 829 629 395 296 167
-------- ------ ------ ------ ------
Total operating revenues . . . . . 21,811 7,412 7,110 3,759 3,263
Operating expenses:
Lease operating expenses and
production taxes . . . . . . . . 3,363 1,478 1,123 777 811
Depreciation, depletion and amortization . 15,933 2,520 2,629 1,666 1,009
General and administrative . . . . . . 3,475 2,186 1,591 1,270 1,200
Cost ceiling writedown . . . . . . . 35,085 -- -- -- --
-------- ------ ------ ------ ------
Total operating expenses . . . . . 57,856 6,184 5,343 3,713 3,020
-------- ------ ------ ------ ------
-30-
Operating income (loss) . . . . . . . . (36,045) 1,228 1,767 46 243
Interest expense . . . . . . . . . . (1,635) (1,200) (1,139) (1,017) (810)
Lawsuit settlement. . . . . . . . . . -- -- -- 3,521 --
-------- ------ ------ ------ ------
Income (loss) before income taxes. . . . . (37,680) 28 628 2,550 (567)
------- ------ ------ ------
Income tax provision<F1>. . . . . . . . 4,120
--------
Net income (loss) . . . . . . . . . . $(41,800) $ 28 $ 628 $2,550 $ (567)
======== ====== ====== ====== ======
Basic and diluted earnings (loss) per share . $ (3.75)
--------
Weighted average shares outstanding . . . . 11,153
--------
AS OF DECEMBER 31,
-------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(In thousands)
Balance Sheet Data (at end of period):
Working capital. . . . . . . . . . . $(15,925) $ (5,985) $ (2,682) $ (1,980) $ (1,769)
Oil and gas properties, net. . . . . . . 80,014 23,968 20,732 17,731 14,257
Total assets. . . . . . . . . . . . 85,968 30,428 24,050 20,005 16,444
Long-term debt, excluding current portion . . 31,837 481 8,723 7,643 7,643
Equity. . . . . . . . . . . . . . 24,749 16,113 7,769 7,410 5,596
_____________________
<FN>
<F1> Upon consummation of the Combination Transaction, the Company was
required to record a one-time non-cash charge to earnings of $5.4
million in connection with establishing a deferred tax liability on
the balance sheet in accordance with SFAS No. 109, "Accounting for
Income Taxes."
</FN>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
OVERVIEW
Miller is an independent oil and gas exploration, development and
production company that has developed a base of producing properties and
-31-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
inventory of prospects in Mississippi, Louisiana, Texas, Michigan, Montana
and North Dakota.
The Company was organized in connection with the Combination
Transaction. The Combined Assets consist of MOC, interests in oil and
natural gas properties from the Affiliated Entities and interests in such
properties owned by certain business partners and investors, including AHC,
Dan A. Hughes, Jr. and SASI Minerals Company. No assets other than those
in which MOC or the Affiliated Entities had an interest were part of the
Combined Assets. The Company and the owners of the Combined Assets entered
into separate agreements that provided for the issuance of approximately
6.9 million shares of the Company's Common Stock and the payment of $48.8
million (net of post-closing adjustments) in cash to certain participants
in the Combination Transaction in exchange for the Combined Assets. The
issuance of the shares and the cash payment were completed upon
consummation of the Company's Offering.
The Combination Transaction closed on February 9, 1998 in connection
with the closing of the Offering. The Offering, including the sale of an
additional 62,500 shares of Common Stock by the Company on March 9, 1998
pursuant to the exercise of the underwriters' over-allotment option,
resulted in net proceeds to the Company of approximately $40.4 million
after expenses.
For further discussion of the Offering and the Combination
Transaction, see Note 1 to the Consolidated Financial Statements.
The Company uses the full cost method of accounting for its oil and
natural gas properties. Under this method, all acquisition, exploration
and development costs, including any general and administrative costs that
directly are attributable to the Company's acquisition, exploration and
development activities, are capitalized in a "full cost pool" as incurred.
The Company records depletion of its full cost pool using the unit-of-
production method. SEC Regulation S-X, Rule 4-10 requires companies reporting
on a full cost basis to apply a ceiling test wherein the capitalized costs
within the full cost pool may not exceed the net present value of the
Company's proved oil and gas reserves plus the lower of cost or market of
unproved properties. Any such excess costs should be charged against earnings.
-32-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
RESULTS OF OPERATIONS
The following table summarizes production volumes, average sales
prices and average costs for the Company's oil and natural gas operations
for the periods presented (in thousands, except per unit amounts):
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ----
(Historical) (Pro Forma)
Production volumes:
Crude oil and condensate (Mbbls) 247.6 47.4 46.5 261.2 206.8 243.0
Natural gas (MMcf) 8,953.3 2,241.2 2,030.0 9,646.2 8,298.2 8,668.0
Natural gas equivalent (MMcfe) 10,438.7 2,525.9 2,309.1 11,213.4 9,539.2 10,126.8
Average sales prices:
Crude oil and condensate ($ per Bbl) $ 10.69 $ 20.33 $ 23.66 $ 10.85 $ 17.94 $ 20.76
Natural gas ($ per Mcf) 2.05 2.60 2.77 2.05 2.50 2.39
Natural gas equivalent ($ per Mcfe) 2.01 2.69 2.91 2.02 2.57 2.54
Average Costs ($ per Mcfe):
Lease operating expenses and
production taxes $ 0.32 $ 0.58 $ 0.49 $ 0.32 $ 0.25 $ 0.22
Depletion, depreciation and
amortization 1.53 1.00 1.14 1.47 0.82 0.81
General and administrative 0.33 0.87 0.69 0.28 0.27 0.20
Because of the significance of the Combination Transaction which
occurred on February 9, 1998, the results of operations have been presented
above on a pro forma and historical basis, and the results of operations
will be described below on a pro forma basis to make the comparative
analyses more meaningful. For additional information regarding the
Combination Transaction, see Note 1 to the Consolidated Financial
Statements and the Pro Forma Statements of Operations in this filing.
-33-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
PRO FORMA YEAR ENDED DECEMBER 31, 1998 COMPARED TO PRO FORMA YEAR
ENDED DECEMBER 31, 1997
Oil and natural gas revenues for the year ended December 31, 1998
decreased 8% to $22.6 million from $24.5 million for the year ended
December 31, 1997. The revenues for the year ended December 31, 1998
include approximately $0.8 million of hedging gains (see "Risk Management
Activities and Derivative Transactions" below). Production volumes for
natural gas during the year ended December 31, 1998 increased 16% to 9,646
MMcf from 8,298 MMcf for the year ended December 31, 1997. Average natural
gas prices decreased 18% to $2.05 per Mcf for the year ended December 31,
1998 from $2.50 per Mcf for the year ended December 31, 1997. Production
volumes for oil during the year ended December 31, 1998 increased 26% to
261 MBbls from 207 MBbls for the year ended December 31, 1997. Average oil
prices decreased 40% to $10.85 per barrel during the year ended
December 31, 1998 from $17.94 per barrel in the year ended December 31,
1997. The oil and gas industry suffered through a year of historically low
oil prices in 1998, caused by a global influx of crude oil supply brought
on by increased Middle-East exports combined with a weaker demand from
Asian markets that were experiencing an economic recession. The natural gas
market also was depressed as a result of abnormally mild winters caused by a
strong El Nino weather pattern that affected the United States during the
past two heating seasons. The Company would have experienced an even
larger decrease in revenue had it not been for the natural gas hedging
gains of approximately $0.8 million and the fact that only 12% of total
operating revenues for 1998 were attributable to oil production.
Lease operating expenses and production taxes for the year ended
December 31, 1998 increased 47% to $3.6 million from $2.4 million for the
year ended December 31, 1997. Lease operating expenses and production
taxes increased primarily due to increased production as described above
and to several workover projects that were completed during the year in an
attempt to enhance production during a period of low commodity prices.
Depreciation, depletion and amortization ("DD&A") expense for the year
ended December 31, 1998 increased 112% to $16.5 million from $7.8 million
for the year ended December 31, 1997. This increase was due to a 79%
increase in the 1998 depletion rate to $1.47 per Mcfe from $.82 per Mcfe
for the year ended December 31, 1997. The higher depletion rate was the
combined result of increased production, an increase in costs subject to
DD&A and a downward revision in estimated proved oil and gas reserves.
General and administrative expense for the year ended December 31,
1998 increased 22% to $3.2 million from $2.6 million for the same period in
-34-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
1997. The rise in general and administrative costs is primarily attributable
to added expenses associated with the Company's initial year as a public
company. These incremental expenses include legal and professional fees paid
to attorneys and accountants, increased rents related to office facilities in
Mississippi and increased salaries and benefits due to additional financial,
technical, operational and administrative staff added during the year.
On March 18, 1999, the Company's board of directors approved a general
and administrative cost reduction plan for 1999. The plan calls for an
overall reduction in general and administrative costs from 1998 of 22%. Cost
reductions will be implemented in several areas, however, the largest cost
reductions will be in the area of salaries and benefits which constitute 61%
of the anticipated total general and administrative reductions for 1999.
At December 31, 1998, the Company recorded a non-cash cost ceiling
writedown of $34.4 million. The writedown was the combined result of a
large downward revision in oil and gas reserve quantities and depressed
commodity prices. Disappointing 2-D seismic-supported drilling results and
drilling cost overruns also contributed to the cost ceiling writedown. The
Company based its ceiling test determination on a price of $1.78 per Mcfe,
which represents the March 1999 closing commodity prices.
Interest expense for the year ended December 31, 1998 increased 45% to
$1.6 million from $1.1 million for the year ended December 31, 1997, as a
result of increased debt levels in 1998 for substantial exploration and
development activities in the Mississippi Salt Basin area.
Net income (loss) for the year ended December 31, 1998 decreased by
$43.6 million (to $35.2 million) from $8.4 million for the year ended
December 31, 1997, as a result of the factors described above.
PRO FORMA YEAR ENDED DECEMBER 31, 1997 COMPARED TO PRO FORMA YEAR
ENDED DECEMBER 31, 1996
Oil and natural gas revenues for the year ended December 31, 1997
decreased 5% to $24.5 million from $25.7 million for the same period in
1996. Production volumes for natural gas during the year ended December 31,
1997 decreased 4% to 8,298 MMcf from 8,668 MMcf for the year ended December
31, 1996. Average natural gas prices increased 5% to $2.50 per Mcf for the
year ended December 31, 1997 from $2.39 per Mcf for the year ended December 31,
1996. Production volumes for oil during the year ended December 31, 1997
decreased 15% to 207 MBbls from 243 MBbls for the year ended December 31, 1996.
Average oil prices decreased 14% to $17.94 per barrel during the year ended
December 31, 1997 from $20.76 per barrel for the year ended December 31, 1996.
This decrease in oil and gas revenues is attributable to decreased production
as well as the cyclical fluctuations in crude oil prices.
-35-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
Lease operating expenses and production taxes for the year ended
December 31, 1997 increased 11% to $2.4 million from $2.2 million for the
year ended December 31, 1996. Lease operating expenses and production
taxes increased primarily due to decreased production while fixed costs
remained greater than variable costs resulting in an increase in operating
expenses per equivalent unit to $.25 per Mcfe for the year ended
December 31, 1997 from $.22 per Mcfe for the year ended December 31, 1996.
DD&A expense for the year ended December 31, 1997 decreased 4% to $7.8
million from $8.2 million for the year ended December 31, 1996. This
decrease was due to decreased production, offset by a 1% increase in the
1997 depletion rate to $0.82 per Mcfe from $0.81 per Mcfe for the year
ended December 31, 1996. The higher depletion rate was the combined result
of decreased production and an increase in costs subject to DD&A.
General and administrative expense for the year ended December 31,
1997 increased 30% to $2.6 million from $2.0 million for the year ended
December 31, 1996, as a result of increases in the number of employees and
related salaries and benefits.
Interest expense for the year ended December 31, 1997 increased 16% to
$1.1 million from $1.0 million in the same period in 1996, as a result of
increased debt levels in 1997 incurred to finance substantial leasehold
acquisition activities in the Mississippi Salt Basin area.
Net income for the year ended December 31, 1997 decreased to $8.4
million from $9.1 million for the year ended December 31, 1996, as a result
of the factors described above.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company's primary sources of capital have been funds
generated by operations, capital contributions and borrowings, primarily
from MOC's shareholders and under bank credit facilities.
The Company has entered into a credit facility (the "Credit Facility")
with Bank of Montreal, Houston Agency ("BMO"). The Credit Facility consists
of a three-year revolving line of credit converting to a three-year term
loan. The amount of credit available during the revolving period and the
debt allowed during the term period may not exceed the Company's "borrowing
base," or the amount of debt that BMO and the other lenders under the Credit
Facility agree can be supported by the cash flow generated by the Company's
producing and non-producing proved oil and natural gas reserves. The
borrowing base may not exceed $75.0 million. Amounts advanced under the Credit
Facility bear interest, payable quarterly, at either (i) BMO's announced
-36-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
prime rate or (ii) the London Inter-Bank Offered Rate plus a margin rate
ranging from 0.75% to 1.62%, as selected by the Company. In addition, the
Company is assessed a commitment fee equal to 0.375% of the unused portion
of the borrowing base, payable quarterly in arrears, until the termination
of the revolving period. At the termination of the revolving period, the
revolving line of credit will convert to a three-year term loan with
principal payable in 12 equal quarterly installments. The Credit Facility
includes certain negative covenants that impose limitations on the Company
and its subsidiaries with respect to, among other things, distributions
with respect to its capital stock, limitations on financial ratios, the
creation or incurrence of liens, the incurrence of additional indebtedness,
making loans and investments and mergers and consolidations. The obligations
of the Company under the Credit Facility are secured by a lien on all real
and hydrocarbon personal property of the Company, including its oil and
natural gas properties. At December 31, 1998, $35.5 million was outstanding
under the Credit Facility.
As a result of decreased proved oil and gas reserves at December
31, 1998, BMO has notified the Company that the Company's borrowing base
was in noncompliance and certain principal obligations were being
accelerated during 1999. Additionally, the Company was in violation of
certain negative covenants under the Credit Facility, primarily as a result
of the $35.1 million non-cash cost ceiling writedown at December 31, 1998.
On April 14, 1999, the Company and BMO signed the Second Amendment
to the Credit Facility which includes: (i) terms requiring the Company to
make principal payments to BMO of $3.0 million by May 1, 1999, $3.0 million
by May 31, 1999 and $1.0 million by the first of each month during the period
July through October 1999, inclusive; (ii) terms requiring that all outstanding
borrowings bear interest at the prime rate plus 3.5%; (iii) a waiver of all
negative covenant violations until October 15, 1999 (the "re-determination
date"); (iv) revised negative covenant provisions which take effect on the
re-determination date; (v) a requirement to submit a revised reserve report to
BMO by October 1, 1999 for a re-determination of the borrowing base; (vi) a
requirement that all proceeds from the sales of oil and gas properties,
additional debt financings or equity offerings, prior to the re-determination
date, must be used to reduce the principal amount outstanding under the Credit
Facility; and (vii) a requirement for a $300,000 amendment fee payable to BMO
at the re-determination date. At the re-determination date, the Company will
be required to make additional payments of principal to the extent its
outstanding borrowings exceed the borrowing base. To fulfill the May 1999
principal and interest obligations, management plans to sell certain oil and
gas property interests to business partners, investors and affiliated entities.
All other principal and interest obligations are expected to be fulfilled
through available cash flows, additional property sales or other financing
sources, including the possible issuance of additional equity securities as
-37-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
well as identifying additional sources for debt financing. There can be no
assurance that the Company will issue additional equity securities or that the
Company will obtain additional sources of debt financing or that the terms of
any such financing will be on more favorable terms than the terms of the Credit
Facility.
On April 14, 1999, the Company signed a $4.7 million note payable
with one its suppliers, Veritas DGC Land, Inc. (the "Veritas Note Payable"),
for the outstanding balance due to Veritas for past services provided in 1998
and 1999. Veritas conducted the 3-D seismic surveys covering substantially all
of the 400 square miles of 3-D seismic data in the Mississippi Salt Basin that
the Company acquired from Veritas in 1998 at a total cost of approximately
$11.2 million. The balance due Veritas was $3.8 million at December 31, 1998,
and has been classified as long-term debt in the accompanying financial
statements. The principal obligation under the Veritas Note Payable is due on
April 15, 2001. Management plans to fulfill the principal obligation under the
Veritas Note Payable from available cash flows, property sales and other
financing sources.
On April 14, 1999, the Company also signed an agreement (the
"Warrant Agreement") to issue warrants that entitle Veritas to subscribe
and purchase shares of the Company's Common Stock in lieu of receiving cash
payments for the accrued interest obligations under the Veritas Note
Payable. The Warrant Agreement requires the Company to issue warrants to
Veritas in conjunction with the signing of the Warrant Agreement, as well
as on the six, 12 and 18 month anniversaries of the Warrant Agreement. The
warrants to be issued must equal 9% of the then current outstanding principal
balance of the Veritas Note Payable. The number of shares to be issued upon
exercise of the warrants will be determined on a five-day average closing
price of the Company's Common Stock. The exercise price of each warrant is
$0.01 per share. The Company has the option, in lieu of issuing warrants, at
the 12 and 18 month anniversaries to make a cash payment to Veritas,
equivalent to 9% of the then current principal balance of the Veritas Note
payable. Under the terms of the Warrant Agreement, all warrants issued will
expire on April 15, 2002. In addition, the Company also signed an agreement
with Veritas that (i) requires the Company to file a registration statement
with the SEC to register shares of Common Stock that are issuable upon
exercise of the above warrants and (ii) grants certain piggy-back registration
rights in connection with the warrants. The shares required to be registered
include only those shares required to be issued at each six month anniversary.
In connection with the closing of the AHC acquisition, the Company has
a note payable to AHC of $3.0 million (at December 31, 1998) which is
payable on the anniversary date of the closing as follows: $0.5 million in
1999, $1.0 million in 2000 and $1.5 million in 2001.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
At December 31, 1998, the Company had a working capital deficit of $5.4
million (excluding the current portion of long-term debt). Management
plans to meet these working capital requirements from available cash
flows, property sales and other financing sources.
The Company has budgeted capital expenditures of approximately $10.6
million for 1999. Capital expenditures will be used to fund drilling and
development activities, the completion of 3-D seismic surveys that were in
process at December 31, 1998 and leasehold acquisitions and extensions in
the Company's project areas. The actual amounts of capital expenditures
and number of wells drilled may differ significantly from such estimates.
Actual capital expenditures for the year ended December 31, 1998 were
approximately $47.0 million. The Company intends to fund its 1999 budgeted
capital expenditures through operational cash flow.
The Company's revenues, profitability, future growth and ability to
borrow funds or obtain additional capital, and the carrying value of its
properties, substantially are dependent on prevailing prices of oil and
natural gas. The Company cannot predict future oil and natural gas price
movements with certainty. Declines in prices received for oil and natural
gas as experienced in 1998 have had an adverse effect on the Company's
financial condition, liquidity, ability to finance capital expenditures and
results of operations. Lower prices in 1998 also had an impact on the
amount of reserves that can be produced economically by the Company.
The Company has experienced and expects to continue to experience
substantial working capital requirements primarily due to the Company's
active exploration and development programs and technology enhancement
programs. While the Company believes that cash flow from operations, property
sales, borrowings and substantially reduced commodity prices should allow the
Company to implement its present business strategy through 1999, additional
debt or equity financing may be required during the remainder of 1999 and in
the future to fund the Company's growth, development and exploration program
and continued technological enhancement and to satisfy its existing
obligations. The failure to obtain and exploit such capital resources could
have a material adverse effect on the Company, including further curtailment
of its exploration and other activities.
RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
The Company uses a variety of derivative instruments ("derivatives")
to manage exposure to fluctuations in commodity prices and interest rates.
To qualify for hedge accounting, derivatives must meet the following
criteria: (i) the item to be hedged exposes the Company to price or
-39-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
interest rate risk; and (ii) the derivative reduces that exposure and is
designated as a hedge.
COMMODITY PRICE HEDGES
In 1997, the Company began using certain derivatives (e.g., NYMEX
futures contracts) for a portion of its natural gas production to achieve a
more predictable cash flow, as well as to reduce the exposure to price
fluctuations. The Company's hedging arrangements apply to only a portion
of its production, provide only partial price protection against declines
in oil and natural gas prices and limit potential gains from future
increases in prices. Such hedging arrangements may expose the Company to
risk of financial loss in certain circumstances, including instances where
production is less than expected, the Company's customers fail to purchase
contracted quantities of oil or natural gas or a sudden unexpected event
materially impacts oil or natural gas prices. For financial reporting
purposes, gains and losses related to hedging are recognized as oil and
natural gas revenues during the period the hedged transactions occur. The
Company expects that the amount of hedge contracts that it has in place
will vary from time to time.
The Company's hedging strategy is to maximize its return on investment
through hedging a portion of its activities relating to natural gas price
volatility. While this strategy should help the Company reduce its
exposure to price risks, it also limits the Company's potential gains from
increases in market prices for natural gas. The Company intends to
continue to hedge up to 50% of its natural gas production to retain a
portion of the potential for greater upside from increases in natural gas
prices, while limiting to some extent the Company's exposure to declines in
natural gas prices. For the year ended December 31, 1998, the Company had
hedged 36% of its natural gas production, and as of December 31, 1998, the
Company had 0.05 Bcf of open natural gas contracts for the months of
February 1999 and March 1999. Subsequent to December 31, 1998, the Company
entered into additional natural gas contracts for approximately 0.39 Bcf
for the time period of April 1999 to June 1999. Open contracts totaling
0.05 Bcf have been settled subsequently in 1999, resulting in hedge profits
of approximately $0.01 million.
INTEREST RATE HEDGE
The Company entered into an interest rate swap agreement, effective
November 2, 1998, to exchange the variable rate interest payment obligation
under the Credit Facility without exchanging the underlying principal
amount. This agreement converts the variable rate debt to fixed rate debt
to reduce the impact of interest rate fluctuations. The notional amount is
-40-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
used to measure interest to be paid or received and does not represent the
exposure to credit loss. The notional amount of the Company's interest
rate swap was $25.0 million at December 31, 1998, and had a fair value of
approximately $0.2 million. The difference between the amounts paid and
received under the swap is accrued and recorded as an adjustment to
interest expense over the term of the hedged agreement, which was to expire
February 9, 2001. Subsequent to year-end, the Company terminated its
interest rate swap agreement and received $0.3 million, which will be
recognized in earnings ratably as the related outstanding loan balance is
amortized.
MARKET RISK INFORMATION
The market risk inherent in the Company's derivatives is the potential
loss arising from adverse changes in commodity prices and interest rates.
The prices of natural gas are subject to fluctuations resulting from
changes in supply and demand. To reduce price risk caused by the market
fluctuations, the Company's policy is to hedge (through the use of
derivatives) future production. Because commodities covered by these
derivatives are substantially the same commodities that the Company sells
in the physical market, no special correlation studies other than
monitoring the degree of convergence between the derivative and cash
markets are deemed necessary. The changes in market value of these
derivatives have a high correlation to the price changes of natural gas.
As all derivatives that were outstanding at December 31, 1998, have been
settled subsequent to year-end, the Company's exposure is limited to the
actual results described above.
EFFECTS OF INFLATION AND CHANGES IN PRICE
In 1998, the Company and the oil and gas industry as a whole,
experienced historically low crude oil prices and substantially depressed
natural gas prices. These lower commodity prices had a negative impact on
the Company's results of operations, cash flow and liquidity. Recent rates
of inflation have had a minimal effect on the Company.
ENVIRONMENTAL AND OTHER REGULATORY MATTERS
The Company's business is subject to certain federal, state and local
laws and regulations relating to the exploration for, and the development,
production and transportation of, oil and natural gas, as well as
environmental and safety matters. Many of these laws and regulations have
become more stringent in recent years, often imposing greater liability on
a larger number of potentially responsible parties. Although the Company
believes it is in substantial compliance with all applicable laws and
regulations, the requirements imposed by laws and regulations frequently
-41-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
are changed and subject to interpretation, and the Company is unable to
predict the ultimate cost of compliance with these requirements or their
effect on its operations. Any suspensions, terminations or inability to
meet applicable bonding requirements could materially adversely affect the
Company's business, financial condition and results of operations.
Although significant expenditures may be required to comply with
governmental laws and regulations applicable to the Company, compliance has
not had a material adverse effect on the earnings or competitive position
of the Company. Future regulations may add to the cost of, or
significantly limit, drilling activity.
YEAR 2000 READINESS DISCLOSURE
This Year 2000 Readiness Disclosure is based upon and partially
repeats information provided by the Company's outside consultants and
others regarding the Year 2000 readiness of the Company and its customers,
suppliers, financial institutions and other parties. Although the Company
believes this information to be accurate, it has not independently verified
such information.
The Company is aware of the issues associated with the programming
code in existing computer systems as the millennium (year 2000) approaches.
The "year 2000" problem is pervasive and complex as virtually every
computer operation will be affected in some way by the rollover of the two
digit year value to 00. The issue is whether computer systems will
properly recognize date sensitive information when the year changes to
2000. Systems that do not properly recognize such information could
generate erroneous data or cause a system to fail.
The Company has initiated a plan to prepare its computer systems and
applications for possible year 2000 problems. Under the plan, the Company
will continue to identify its computer hardware and software systems and
equipment with embedded computer chips; assess the effects of the year 2000
issues; and enhance the plan by developing the steps necessary to identify,
correct or reprogram and test systems for year 2000 compliance. The
Company has completed approximately 75% of the year 2000 modifications on
its networked computer applications. The Company will continue to assess
the impact of the year 2000 issue on its systems and applications
throughout 1999. The Company's goal is to perform tests of its systems and
applications during 1999 and to have systems and applications year 2000
ready by July 1999, allowing the remaining time to be used for validation
and testing.
The Company expects to incur internal staff costs as well as
consulting and other expenses to prepare the systems for the year 2000.
-42-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
The Company expects to spend no more than $75,000 in connection with
identifying, assessing, remediating and testing year 2000 issues. The
Company expects that it will expense all costs associated with system
changes. The Company also may invest in new or upgraded technology which
has a definable value lasting beyond 2000. In these instances, where year
2000 compliance is merely ancillary, the Company may capitalize and
depreciate such an asset over its estimated useful life.
Based on currently available information, management does not
anticipate that the costs to address the year 2000 issues will have a
material adverse impact on the Company's financial condition, results of
operations or liquidity. However, the extent to which the computer
operations and other systems of the Company's important third parties are
adversely affected could, in turn, affect the Company's ability to
communicate with third parties and could have a material adverse effect on
the operations of the Company (including but not limited to failures in
service, disruptions in the Company's ability to bill customers and pay
suppliers and the possible slowdown of certain computer-dependent
processes).
The Company has made inquiries of third party vendors, suppliers and
customers, which have a material relationship with the Company, as to the
status of their year 2000 readiness. To date, the Company has not received
sufficient responses from these third parties that would enable the Company
to assess the status of the third parties' readiness for the year 2000.
Unreadiness by these third parties would expose the Company to the
potential for loss and impairment of business processes and activities.
The Company is assessing these risks and is creating contingency plans
intended to address perceived risks.
The costs of the project and the date on which the Company expects to
complete the year 2000 modifications are based on management's best
estimates. There can be no guarantee that these estimates will be
achieved, and actual results could differ from those anticipated. Specific
factors that might cause differences include, but are not limited to, the
ability of other companies on which the Company's systems rely to modify or
convert their systems to be year 2000 ready, the ability of all third
parties who have business relationships with the Company to continue their
businesses without interruption and similar uncertainties. As a result,
the Company is in the process of evaluating possible internal and external
scenarios that might have an adverse impact on the Company. The Company
also recognizes that a contingency plan must be developed in the event the
Company's systems cannot be made year 2000 compliant on a timely basis.
The Company expects to complete the development of this contingency plan by
July 1999.
-43-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS (CONTINUED)
NEW ACCOUNTING STANDARD
In 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No.
133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair value. SFAS No. 133 requires that changes
in the derivative's fair value be recognized currently in earnings unless
specific hedge accounting criteria are met. Special accounting for
qualifying hedges allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a
company must formally document, designate and assess the effectiveness of
transactions that receive hedge accounting.
SFAS No. 133 is effective for fiscal years beginning after June 15,
1999. The Company has not yet quantified the impacts of adopting SFAS No.
133 on its financial statements and has not determined the timing of or
method of its adoption of SFAS No. 133. However, SFAS No. 133 could
increase volatility in earnings and other comprehensive income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The information required hereunder is included in "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Risk Management Activities and Derivative Transactions" in Item 7, which is
incorporated by reference in this Item 7A.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The information required hereunder is included in this report as set
forth in the "Index to Financial Statements" on Page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information regarding directors of the Company contained under the
captions "Board of Directors," "Executive Officers" and "Section 16(a)
Beneficial Ownership Reporting Compliance" in the definitive Proxy
-44-
Statement for the Company's annual meeting of stockholders to be held on
June 3, 1999 is here incorporated by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The information contained under the captions "Compensation of
Directors" and "Executive Compensation" in the definitive Proxy Statement
for the Company's annual meeting of stockholders to be held on June 3, 1999
is here incorporated by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information contained under the captions "Voting Securities,"
"Security Ownership of Certain Beneficial Owners" and "Security Ownership
of Management" in the definitive Proxy Statement for the Company's annual
meeting of stockholders to be held on June 3, 1999 is here incorporated by
reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information contained under the captions "Voting Securities,"
"Security Ownership of Certain Beneficial Owners" and "Security Ownership
of Management" in the definitive Proxy Statement for the Company's annual
meeting of stockholders to be held on June 3, 1999 is here incorporated by
reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES, AND REPORTS ON FORM
8-K.
ITEM 14(a)(1). FINANCIAL STATEMENTS. See "Index to Financial
Statements" set forth on page F-1.
ITEM 14(a)(2). FINANCIAL STATEMENT SCHEDULES. Financial statement
schedules have been omitted because they are either not required, not
applicable or the information required to be presented is included in the
Company's financial statements and related notes.
ITEM 14(a)(3). EXHIBITS. The following exhibits are filed as a part
of this report.
EXHIBIT NO. DESCRIPTION
2.1 Exchange and Combination Agreement dated November 12, 1997.
Previously filed as an exhibit to the Company's Registration
-45-
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(a) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(b) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(c) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.3(a) Agreement for Purchase and Sale dated November 25, 1997
between Amerada Hess Corporation and Miller Oil Corporation.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.3(b) First Amendment to Agreement for Purchase and Sale dated
January 7, 1998. Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and
here incorporated by reference.
3.1 Certificate of Incorporation of the Registrant. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
3.2 Bylaws of the Registrant. Previously filed as an exhibit to
the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1998, and here incorporated by reference.
4.1 Certificate of Incorporation. See Exhibit 3.1.
4.2 Bylaws. See Exhibit 3.2.
4.3 Form of Specimen Stock Certificate. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.1(a) Stock Option and Restricted Stock Plan of 1997.<F*>
Previously filed as an exhibit to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997, and here
incorporated by reference.
-46-
10.1(b) Form of Stock Option Agreement.<F*> Previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.1(c) Form of Restricted Stock Agreement.<F*> Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.2 Form of Director and Officer Indemnity Agreement. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.<F*>
10.3 Form of Employment Agreement for Kelly E. Miller, William J.
Baumgartner, Lew P. Murray and Charles A. Morrison. Previously
filed as an exhibit to the Company's Registration Statement
on Form S-1 (333-40383), and here incorporated by
reference.<F*>
10.4 Lease Agreement between Miller Oil Corporation and C.E. and
Betty Miller, dated July 24, 1996. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.5 Letter Agreement dated November 10, 1997, between Miller Oil
Corporation and C.E. Miller, regarding sale of certain assets.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
10.6 Amended Service Agreement dated January 1, 1997, between
Miller Oil Corporation and Eagle Investments, Inc. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.7 Form of Registration Rights Agreement (included as Exhibit E
to Exhibit 2.1). Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and
here incorporated by reference.
10.8 Consulting Agreement dated June 1, 1996 between Miller Oil
Corporation and Frank M. Burke, Jr., with amendment.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
10.9 $2,500,000 Promissory Note dated November 26, 1997 between
Miller Oil Corporation and the C.E. Miller Trust. Previously
-47-
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.10 Form of Indemnification and Contribution Agreement among the
Registrant and the Selling Stockholders. Previously filed as
an exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.11 Credit Agreement between Miller Oil Corporation and Bank of
Montreal dated February 9, 1998. Previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.12 Guaranty Agreement by Miller Exploration Company in favor of
Bank of Montreal dated February 9, 1998. Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.13 $75,000,000 Promissory Note of Miller Oil Corporation to Bank
of Montreal dated February 9, 1998. Previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.14 Mortgage (Michigan) between Miller Oil Corporation and James
Whitmore, as trustee for the benefit of Bank of Montreal,
dated February 9, 1998. Previously filed as an exhibit to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997, and here incorporated by reference.
10.15 Mortgage, Deed of Trust, Assignment of Production, Security
Agreement and Financing Statement (Mississippi) between Miller
Oil Corporation and James Whitmore, as trustee for the benefit
of Bank of Montreal, dated February 9, 1998. Previously filed
as an exhibit to the Company's Annual Report on Form 10-K for
the year ended December 31, 1997, and here incorporated by
reference.
10.16 Mortgage, Deed of Trust, Assignment of Production, Security
Agreement and Financing Statement (Texas) between Miller Oil
Corporation and James Whitmore, as trustee for the benefit of
Bank of Montreal, dated February 9, 1998. Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
-48-
10.17 First Amendment to Credit Agreement between Miller Oil
Corporation and Bank of Montreal dated June 24, 1998.
10.18 Second Amendment to Credit Agreement between Miller Oil
Corporation and Bank of Montreal dated April 14, 1999.
10.19 Agreement between Eagle Investments, Inc. and Miller Oil
Corporation, dated April 1, 1999.
10.20 $4,696,040.60 Note between Miller Exploration Company and
Veritas DGC Land, Inc., dated April 14, 1999.
10.21 Warrant between Miller Exploration Company and Veritas DGC
Land, Inc., dated April 14, 1999.
10.22 Registration Rights Agreement between Miller Exploration
Company and Veritas DGC Land, Inc., dated April 14, 1999.
11.1 Computation of Earnings per Share.
21.1 Subsidiaries of the Registrant. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
23.1 Consent of S.A. Holditch & Associates.
23.2 Consent of Miller and Lents, Ltd.
23.3 Consent of Arthur Andersen LLP.
24.1 Limited Power of Attorney.
27.1 Financial Data Schedule.
____________________
<F*> Management contract or compensatory plan or arrangement.
ITEM 14(b). The Company filed no reports on Form 8-K during the last
quarter of 1998.
-49-
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
MILLER EXPLORATION COMPANY
By /s/Kelly E. Miller
Kelly E. Miller
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
April 15, 1999 /s/*C.E. Miller
C. E. Miller
Chairman of the Board
April 15, 1999 /s/Kelly E. Miller
Kelly E. Miller, Director
(Principal Executive Officer)
April 15, 1999 /s/William J. Baumgartner
William J. Baumgartner, Director
(Principal Financial and Accounting
Officer)
April 15, 1999 /s/*Frank M. Burke, Jr.
Frank M. Burke, Jr., Director
April ___, 1999 _____________________________________
Dan A. Hughes, Jr., Director
April 15, 1999 /s/*William Casey McManemin
William Casey McManemin, Director
April 15, 1999 /s/*Kenneth J. Foote
Kenneth J. Foote, Director
April 15, 1999 /s/*Richard J. Burgess
Richard J. Burgess, Director
*By /s/William J. Baumgartner
William J. Baumgartner, Director
Attorney-in-Fact
-50-
INDEX TO FINANCIAL STATEMENTS
PAGE
CONSOLIDATED FINANCIAL STATEMENTS OF MILLER EXPLORATION COMPANY
Report of Independent Public Accountants . . . . . . . . . . . . . . F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997 . . . . F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1998, 1997 and 1996 . . . . . . . . . . . . . . . . . . F-4
Consolidated Statements of Equity for the Years Ended
December 31, 1998, 1997 and 1996 . . . . . . . . . . . . . . . . . . F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1998, 1997 and 1996 . . . . . . . . . . . . . . . . . . F-6
Notes to Consolidated Financial Statements . . . . . . . . . . . . . F-7
Supplemental Quarterly Financial Data (unaudited). . . . . . . . . . F-26
UNAUDITED PRO FORMA FINANCIAL DATA:
Pro Forma Statement of Operations for the Years Ended
December 31, 1998 and 1997 (unaudited) . . . . . . . . . . . . . . . F-27
F-1
ARTHUR ANDERSEN LLP
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of Miller Exploration Company:
We have audited the accompanying consolidated balance sheets of MILLER
EXPLORATION COMPANY (a Delaware corporation) and subsidiaries as of
December 31, 1998 and 1997, and the related consolidated statements of
operations, equity and cash flows for each of the three years in the
period ended December 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Miller Exploration
Company and subsidiaries as of December 31, 1998 and 1997, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1998, in conformity with generally accepted
accounting principles.
/S/ARTHUR ANDERSEN LLP
Detroit, Michigan
April 15, 1999
F-2
MILLER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)
AS OF DECEMBER 31,
---------------------
1998 1997
-------- --------
(NOTE 1)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents . . . . . . . . . . . . . $ 22 $ 146
Accounts receivable . . . . . . . . . . . . . . . 3,959 2,109
Inventories, prepaids and advances to operators . . . . . . 978 994
Other current assets (Note 2) . . . . . . . . . . . . -- 2,936
-------- --------
Total current assets . . . . . . . . . . . . . . 4,959 6,185
-------- --------
OIL AND GAS PROPERTIES at cost (full cost method):
Proved oil and gas properties . . . . . . . . . . . . 103,272 29,324
Unproved oil and gas properties . . . . . . . . . . . 39,995 7,069
Less-Accumulated depreciation, depletion and amortization. . . (63,253) (12,425)
-------- --------
Net oil and gas properties. . . . . . . . . . . . 80,014 23,968
-------- --------
OTHER ASSETS (Note 2) . . . . . . . . . . . . . . . . 995 275
-------- --------
Total assets . . . . . . . . . . . . . . . . $ 85,968 $ 30,428
======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt. . . . . . . . . . . $ 10,500 $ 7,697
Accounts payable . . . . . . . . . . . . . . . . 6,819 3,870
Accrued expenses and other current liabilities . . . . . . 3,565 603
-------- --------
Total current liabilities . . . . . . . . . . . . 20,884 12,170
-------- --------
LONG-TERM DEBT. . . . . . . . . . . . . . . . . . . 31,837 481
F-3
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . 6,883 --
DEFERRED REVENUE . . . . . . . . . . . . . . . . . . 1,615 1,664
COMMITMENTS AND CONTINGENCIES (Note 9)
EQUITY:
Preferred stock, $0.01 par value; 2,000,000 shares authorized;
none outstanding . . . . . . . . . . . . . . . -- --
Common stock, $0.01 par value; 20,000,000 shares authorized;
12,492,597 shares outstanding at December 31, 1998. . . . 126 --
Additional paid in capital . . . . . . . . . . . . . 67,136 --
Deferred compensation. . . . . . . . . . . . . . . (876) --
Combined equity. . . . . . . . . . . . . . . . . -- 8,588
Retained earnings (deficit). . . . . . . . . . . . . (41,637) 7,525
-------- --------
Total equity . . . . . . . . . . . . . . . . 24,749 16,113
-------- --------
Total liabilities and equity . . . . . . . . . . . $ 85,968 $ 30,428
======== ========
The accompanying notes are an integral part of these
Consolidated Financial Statements.
F-4
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
FOR THE YEAR
ENDED DECEMBER 31,
-----------------------------------
1998 1997 1996
---- ---- ----
(NOTE 1) (NOTE 1)
REVENUES:
Natural gas . . . . . . . . . . . . $ 18,336 $ 5,819 $ 5,614
Crude oil and condensate . . . . . . . . 2,646 964 1,101
Other operating revenues . . . . . . . . 829 629 395
-------- ------- -------
Total operating revenues. . . . . . . 21,811 7,412 7,110
-------- ------- -------
OPERATING EXPENSES:
Lease operating expenses and production taxes . 3,363 1,478 1,123
Depreciation, depletion and amortization. . . 15,933 2,520 2,629
General and administrative . . . . . . . 3,475 2,186 1,591
Cost ceiling writedown. . . . . . . . . 35,085 -- --
-------- ------- -------
Total operating expenses. . . . . . . 57,856 6,184 5,343
-------- ------- -------
OPERATING INCOME (LOSS). . . . . . . . . . (36,045) 1,228 1,767
-------- ------- -------
INTEREST EXPENSE . . . . . . . . . . . . (1,635) (1,200) (1,139)
-------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES . . . . . . (37,680) 28 628
-------- ------- -------
INCOME TAX PROVISION (Note 3). . . . . . . . 4,120
--------
NET INCOME (LOSS). . . . . . . . . . . . $(41,800) $ 28 $ 628
======== ======= =======
F-5
EARNINGS (LOSS) PER SHARE (Note 4)
Basic . . . . . . . . . . . . . . $ (3.75)
========
Diluted. . . . . . . . . . . . . . $ (3.75)
========
The accompanying notes are an integral part of these
Consolidated Financial Statements.
F-6
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(IN THOUSANDS)
ADDITIONAL RETAINED
PREFERRED COMMON PAID IN DEFERRED COMBINED EARNINGS
STOCK STOCK CAPITAL COMPENSATION EQUITY (DEFICIT)
----- ----- ------- ------------ ------ --------
BALANCE-December 31, 1995 $ -- $ -- $ -- $ -- $ 141 $ 7,269
Contributions and return of
capital, net -- -- -- -- (69) --
Net income -- -- -- -- -- 628
Dividends declared -- -- -- -- -- (200)
------- ---- ------- ----- ------ --------
BALANCE-December 31, 1996 -- -- -- -- 72 7,697
Contributions and return of
capital, net -- -- -- -- 8,516 --
Net income -- -- -- -- -- 28
Dividends declared -- -- -- -- -- (200)
------- ---- ------- ----- ------ --------
BALANCE-December 31, 1997 -- -- -- -- 8,588 7,525
Net loss and capital prior to
S Corporation termination -- -- -- -- 172 (163)
S Corporation termination -- -- 16,122 -- (8,760) (7,362)
Common stock issuance -- 56 39,983 -- -- --
Combination transaction -- 69 10,156 -- -- --
Restricted stock issuance -- 1 875 (876) -- --
Net loss after S Corporation
termination -- -- -- -- -- (41,637)
------- ---- ------- ----- ------ --------
BALANCE-December 31, 1998 $ -- $126 $67,136 $(876) $ -- $(41,637)
======= ==== ======= ===== ====== ========
The accompanying notes are an integral part of these
Consolidated Financial Statements.
F-7
MILLER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
FOR THE YEAR ENDED
DECEMBER 31,
--------------------------------
1998 1997 1996
---- ---- ----
(NOTE 1) (NOTE 1)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) . . . . . . . . . . . . . . . $(41,800) $ 28 $ 628
Adjustments to reconcile net income (loss) to net cash from
operating activities-
Depreciation, depletion and amortization . . . . . 15,933 2,520 2,629
Cost ceiling writedown . . . . . . . . . . . 35,085 -- --
Deferred income taxes. . . . . . . . . . . . (1,052) -- --
Deferred revenue . . . . . . . . . . . . . (49) (58) (27)
Changes in assets and liabilities-
Accounts receivable . . . . . . . . . . . (1,850) 137 (1,010)
Other current assets . . . . . . . . . . . 2,952 (3,432) (360)
Other assets. . . . . . . . . . . . . . (118) -- --
Accounts payable . . . . . . . . . . . . 6,786 2,761 252
Accrued expenses and other current liabilities . . 2,962 34 50
-------- ------- -------
Net cash flows provided by operating activities . 18,849 1,990 2,162
-------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Exploration and development expenditures . . . . . . . (46,950) (8,822) (6,184)
Acquisition of properties . . . . . . . . . . . . (51,011) -- --
Advance payment of natural gas sales. . . . . . . . . -- -- 185
Proceeds from sale of oil and gas properties and purchases of
equipment, net . . . . . . . . . . . . . . . 3,065 2,955 1,256
-------- ------- -------
Net cash flows used in investing activities . . (94,896) (5,867) (4,743)
-------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of principal. . . . . . . . . . . . . . (5,178) (572) (55)
Borrowing on long-term debt. . . . . . . . . . . . 35,500 3,512 3,135
Contributions, return of capital and stock proceeds, net . . 45,601 873 (69)
Payments of dividends. . . . . . . . . . . . . . -- (200) (200)
-------- ------- -------
Net cash flows provided by financing activities . . 75,923 3,613 2,811
-------- ------- -------
F-8
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS . . . . . . . . . . . . . . . . . (124) (264) 230
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE
PERIOD. . . . . . . . . . . . . . . . . . . 146 410 180
-------- ------- -------
CASH AND CASH EQUIVALENTS AT END OF THE PERIOD. . . . . . . $ 22 $ 146 $ 410
======== ======= =======
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for--
Interest . . . . . . . . . . . . . . . . . $ 1,571 $ 1,373 $ 1,122
======== ======= =======
The accompanying notes are an integral part of these
Consolidated Financial Statements.
F-9
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF OPERATIONS
THE COMBINATION TRANSACTION
Miller Exploration Company ("Miller" or the "Company") was formed as a
Delaware corporation in November 1997 to serve as the surviving company
upon the completion of a series of combination transactions (the
"Combination Transaction"). The first part of the Combination Transaction
included the following activities: Miller acquired all of the outstanding
capital stock of Miller Oil Corporation ("MOC"), the Company's predecessor,
and certain oil and gas interests (collectively, the "Combined Assets")
owned by Miller & Miller, Inc., Double Diamond Enterprises, Inc., Frontier
Investments, Inc., Oak Shores Investments, Inc., Eagle Investments, Inc.
(d/b/a Victory, Inc.) and Eagle International, Inc. (the "affiliated
entities," all Michigan corporations owned by Miller family members who are
beneficial owners of MOC) in exchange for an aggregate consideration of
approximately 5.3 million shares of Common Stock of Miller. The operations
of all of these entities had been managed through the same management team,
and had been owned by the same members of the Miller family. Miller
completed the Combination Transaction concurrently with consummation of an
initial public offering (the "Offering").
INITIAL PUBLIC OFFERING
On February 9, 1998, the Company completed the Offering of its Common
Stock and concurrently completed the Combination Transaction. On that
date, the Company sold 5.5 million shares of its Common Stock for an
aggregate purchase price of $44.0 million. On March 9, 1998, the Company
sold an additional 62,500 shares of its Common Stock for an aggregate
purchase price of $0.5 million, pursuant to the exercise of the
underwriters' over-allotment option.
The consolidated financial statements as of and for the year ended
December 31, 1998 include the accounts of the Company and its subsidiaries
after taking into effect the Offering and the Combination Transaction. The
financial statements as of and for the periods ending in 1997 and 1996
include the accounts of the Company and its affiliated entities (as defined
above) before the Offering and the Combination Transaction.
OTHER TRANSACTIONS COMPLETED CONCURRENTLY WITH THE INITIAL PUBLIC
OFFERING
In addition to the above combined activities of the Company, the
second part of the Combination Transaction that was consummated
concurrently with the Offering was the exchange by the Company of an
F-10
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(1) ORGANIZATION AND NATURE OF OPERATIONS (CONTINUED)
aggregate of approximately 1.6 million shares of Common Stock for interests
in certain other oil and gas properties that were owned by non-affiliated
parties. Because these interests were acquired from individuals who were
not under the common ownership and management of the Company, these
exchanges were accounted for under the purchase method of accounting. Under
that method, the properties were recorded at their estimated fair value at
the date on which the exchange was consummated (February 9, 1998). The
financial statements as of and for the periods ending in 1997 and 1996 do
not include the activities of these non-affiliated interests.
In November 1997, the Company entered into a Purchase and Sale
Agreement, whereby the Company acquired interests in certain crude oil and
natural gas producing properties and undeveloped properties from Amerada Hess
Corporation ("AHC") for $48.8 million, net of post-closing adjustments. This
purchase was consummated concurrently with the Offering. This acquisition was
accounted for under the purchase method of accounting and was financed with
the use of proceeds from the Offering and with new bank borrowings. The
financial statements as of and for the periods ending in 1997 and 1996 do not
include the activities of these AHC interests.
In February 1998, MOC terminated its S corporation status which
required the Company to reclassify combined equity and retained earnings as
additional paid-in capital.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements of the Company include the
accounts of the Company and its subsidiaries after elimination of all
intercompany accounts and transactions.
PRINCIPLES OF COMBINATION
The accompanying financial statements as of and for the periods ending
in 1997 and 1996 include the accounts of Miller, MOC and the other
affiliated entities (as defined above), all of which share common ownership
and management. The Combination Transaction was accounted for as a
reorganization of entities under common control in a manner similar to a
pooling-of-interests, as prescribed by Securities and Exchange Commission
("SEC") Staff Accounting Bulletin No. 47 because of the high degree of
common ownership among, and the common control of, the combined entities.
Accordingly, the accompanying accounts as of and for the periods ending in
F-11
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(1) ORGANIZATION AND NATURE OF OPERATIONS (CONTINUED)
1997 and 1996 have been prepared using the historical costs and results of
operations of the affiliated entities. There were no differences in
accounting methods or their application among the combining entities. All
intercompany balances have been eliminated.
NATURE OF OPERATIONS
The Company is a domestic, independent energy company engaged in the
exploration, development and production of crude oil and natural gas. The
Company has established exploration efforts concentrated primarily in four
regions: the Mississippi Salt Basin of central Mississippi; the onshore
Gulf Coast region of Texas and Louisiana; the Blackfeet Indian Reservation
of the southern Alberta Basin in Montana; and the Michigan Basin.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting and capitalizes
all costs related to its exploration and development program, including the
cost of nonproductive drilling and surrendered acreage. Such capitalized
costs include lease acquisition, geological and geophysical work, delay
rentals, drilling, completing and equipping oil and gas wells, together
with internal costs directly attributable to property acquisition,
exploration and development activities. Under this method, the proceeds
from the sale of oil and gas properties are accounted for as reductions to
capitalized costs, and gains and losses are not recognized. The
capitalized costs are amortized on an overall unit-of-production method
based on total estimated proved oil and gas reserves. Additionally, certain
costs associated with major development projects and all costs of
unevaluated leases are excluded from the depletion base until reserves
associated with the projects are proved or until impairment occurs.
To the extent that capitalized costs (net of accumulated depreciation,
depletion and amortization) exceed the sum of discounted estimated future
net cash flows from proved oil and gas reserves (using unescalated prices
and costs and a 10% per annum discount rate) and the lower of cost or
market value of unproved properties, such excess costs are charged against
earnings. At December 31, 1998, the Company recognized a non-cash cost
ceiling writedown in the amount of $35.1 million. The Company based its
ceiling test determination on a price of $1.78 per Mcfe, which represents
the March 1999 closing commodity prices. The Company did not have any such
charges against earnings during the years ended December 31, 1997 or 1996.
F-12
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
PROPERTY AND EQUIPMENT
Property and equipment is included in other assets in the accompanying
balance sheets and consists primarily of office furniture, equipment and
computer software and hardware. Depreciation and amortization are
calculated using straight-line and accelerated methods over the estimated
useful lives of the related assets, which typically range from five to 20
years.
REVENUE RECOGNITION
Crude oil and natural gas revenues are recognized as production takes
place and the sale is completed and the risk of loss transfers to a third
party purchaser.
INVENTORIES
Inventories consist of oil field casing, tubing and related equipment
for wells. Inventories are valued at the lower of cost (first-in, first-
out method) or market.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents are comprised of cash and U.S. Government
securities with original maturities of three months or less.
OTHER CURRENT ASSETS
At December 31, 1997, other current assets included a $2.5 million
down payment of the purchase price to AHC. Additionally, $0.4 million of
costs directly attributable to the Offering had been deferred, and were
subsequently charged against the gross proceeds of the Offering.
RECLASSIFICATIONS
Certain reclassifications have been made to the prior year financial
statements to conform with the 1998 presentation.
F-13
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
USE OF ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenue and expense during
the reporting periods. Accordingly, actual results could differ from these
estimates. Significant estimates include depreciation, depletion and
amortization of proved oil and natural gas properties. Oil and natural gas
reserve estimates, which are the basis for unit-of-production depletion and
the cost ceiling test, are inherently imprecise and are expected to change
as future information becomes available.
OTHER
For significant accounting policies regarding income taxes, see Note
3; for earnings per share, see Note 4; for financial instruments, see Note
7; for risk management activities and derivative transactions, see Note 8;
and for stock-based compensation, see Note 10.
(3) INCOME TAXES
The Company accounts for income taxes under the provisions of
Statement of Financial Accounting Standards ("SFAS") No. 109, "Accounting
for Income Taxes." SFAS No. 109 requires the asset and liability approach
for income taxes. Under this approach, deferred tax assets and liabilities
are recognized based on anticipated future tax consequences attributable to
differences between financial statement carrying amounts of assets and
liabilities and their respective tax bases.
Before consummation of the Offering, the Company and the combined
entities either elected to be treated as S corporations under the Internal
Revenue Code or were otherwise not taxed as entities for federal income tax
purposes. The taxable income or loss has therefore been allocated to the
equity owners of the Company and the affiliated entities. Accordingly, no
provision was made for income taxes in the accompanying financial
statements as of and for the periods ending in 1997 and 1996.
F-14
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(3) INCOME TAXES (CONTINUED)
Due to the use of different methods for tax and financial reporting
purposes in accounting for various transactions, the Company has temporary
differences between its tax basis and financial reporting basis. Had the
Company been a taxpaying entity before consummation of the Offering, a
deferred tax liability of approximately $5.4 million at December 31, 1997,
would have been recorded for this difference, with a corresponding
reduction in retained earnings.
Included in the deferred income tax provision for the year ended
December 31, 1998, is a one-time non-cash accounting charge of $5.4 million
to record net deferred tax liabilities, for the differences between tax
basis and financial reporting basis, upon consummation of the Offering and
the termination of MOC's S corporation status. The effective income tax
rate for the Company for the year ended December 31, 1998, was different
than the statutory federal income tax rate for the following reasons (in
thousands):
Net loss . . . . . . . . . . . . . . . . . . . . . $(41,800)
Add back:
Income tax provision . . . . . . . . . . . . . . . . 4,120
--------
Pre-tax loss . . . . . . . . . . . . . . . . . . . . (37,680)
Income tax provision (benefit) at the federal statutory rate . . . . (12,811)
Deferred tax liabilities recorded upon the Offering . . . . . . . 5,392
Valuation allowance. . . . . . . . . . . . . . . . . . 11,700
All other, net . . . . . . . . . . . . . . . . . . . (161)
--------
Income tax provision . . . . . . . . . . . . . . . . . $ 4,120
========
The components of the provision of income taxes for the year
ended December 31, 1998 are as follows (in thousands):
F-15
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(3) INCOME TAXES (CONTINUED)
Currently payable . . . . . . . . . . . . . . . . . . $ --
Deferred to future periods . . . . . . . . . . . . . . . 4,120
------
Total income taxes. . . . . . . . . . . . . . . . . . $4,120
======
The principal components of the Company's deferred tax assets
(liabilities) recognized in the balance sheet as of December 31, 1998 are
as follow (in thousands):
Deferred tax liabilities:
Unsuccessful well and lease costs . . . . . . . . . . . $ (3,655)
Intangible drilling costs . . . . . . . . . . . . . . (3,923)
Financial statement carrying value in excess of tax basis
of purchased assets. . . . . . . . . . . . . . . . (1,503)
Other. . . . . . . . . . . . . . . . . . . . . (807)
Deferred tax assets:
Net operating loss carryforward . . . . . . . . . . . . 14,705
--------
Net deferred tax assets . . . . . . . . . . . . . . . . 4,817
Less: Valuation allowance . . . . . . . . . . . . . . . (11,700)
--------
Net deferred tax liability . . . . . . . . . . . . . . . $ (6,883)
========
SFAS No. 109 requires that the Company record a valuation allowance when
it is more likely than not that some portion or all of the deferred tax
assets will not be realized. In the fourth quarter of fiscal 1998, the
Company recorded a $35.1 million cost ceiling writedown. The writedown and
significant tax net operating loss carryforwards resulted in a net deferred
tax asset at December 31, 1998. The Company believes it is more likely
than not that a portion of the deferred tax assets will not be realized,
therefore, the Company has recorded a valuation allowance. At December 31,
1998, the Company had regular tax net operating loss carryforwards of
F-16
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(3) INCOME TAXES (CONTINUED)
approximately $3.0 million. This loss carryforward amount will expire
during 2012. The Company also had a percentage depletion carryforward of
approximately $0.2 million at December 31, 1998, which is available to
offset future federal income taxes payable and has no expiration date.
(4) EARNINGS PER SHARE
In accordance with the provisions of SFAS No. 128, "Earnings per
Share," basic earnings per share is computed on the basis of the weighted-
average number of common shares outstanding during the periods. Diluted
earnings per share is computed based upon the weighted-average number of
common shares plus the assumed issuance of common shares for all
potentially dilutive securities.
Earnings per share has been omitted from the statement of operations
for the years ended December 31, 1997 and 1996, since such information is
not meaningful and the historically combined Company (prior to the
Combination Transaction) was not a separate legal entity with a singular
capital structure. The computation of earnings per share for the year ended
December 31, 1998 is as follows (in thousands, except per share data):
Net loss attributable to basic and diluted EPS. . . . . . . $(41,800)
Average common shares outstanding applicable to basic EPS . . . 11,153
Add: options treasury shares and restricted stock . . . . . --
--------
Average common shares outstanding applicable to diluted EPS . . 11,153
Earnings (loss) per share:
Basic . . . . . . . . . . . . . . . . . . . $ (3.75)
--------
Diluted . . . . . . . . . . . . . . . . . . $ (3.75)
--------
Options and restricted stock were not included in the computation of
diluted earnings per share for the year ended December 31, 1998 because
their effect was antidilutive.
F-17
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(5) NET PRODUCTION PAYMENTS
During 1995, the Company transferred a limited-term working interest,
based on specified volumes, in certain natural gas producing properties to
Miller Shale Limited Partnership ("MSLP"), an affiliated entity. Under the
terms of the agreement, the Company will receive payments equal to 97% of
the net profits from MSLP, as defined in the agreement, arising from the
production of those properties.
The payments received by the Company are reflected on a gross basis in
the accompanying consolidated financial statements and the associated
proved reserves also are reflected in the accompanying supplemental oil and
gas disclosures to the consolidated financial statements.
During 1995 and 1996, the Company also received advance cash payments
from MSLP of approximately $1.6 million. These proceeds have been recorded
as deferred revenue, which will be recognized in income as the natural gas
volumes under the agreement are delivered.
The payments to be received by the Company, arising from this
agreement, are collateralized by a mortgage on the respective natural gas
properties.
(6) LONG-TERM DEBT
In connection with the Offering, the Company entered into a credit
facility (the "Credit Facility") with Bank of Montreal, Houston Agency
("BMO"). The Credit Facility consists of a three-year revolving line of
credit converting to a three-year term loan. The amount of credit available
during the revolving period and the debt allowed during the term period may
not exceed the Company's "borrowing base," or the amount of debt that BMO
and the other lenders under the Credit Facility agree can be supported by
the cash flow generated by the Company's producing and non-producing proved
oil and gas reserves. The borrowing base may not exceed $75.0 million.
Amounts advanced under the Credit Facility bear interest, payable quarterly,
at either (i) BMO's announced prime rate or (ii) the London Inter-Bank
Offered Rate plus a margin rate ranging from 0.75% to 1.62%, as selected by
the Company. In addition, the Company is assessed a commitment fee equal to
0.375% of the unused portion of the borrowing base, payable quarterly in
arrears, until the termination of the revolving period. At the termination
of the revolving period, the revolving line of credit will convert to a
three-year term loan with principal payable in 12 equal quarterly installments.
The Credit Facility includes certain negative covenants that impose
F-18
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(6) NOTES PAYABLE AND LONG-TERM DEBT (CONTINUED)
limitations on the Company and its subsidiaries with respect to, among other
things, distributions with respect to its capital stock, limitations on
financial ratios, the creation or incurrence of liens, the incurrence of
additional indebtedness, making loans and investments and mergers and
consolidations. The obligations of the Company under the Credit Facility are
secured by a lien on all real and personal hydrocarbon property of the
Company, including its oil and gas properties. At December 31, 1998, $35.5
million was outstanding under the Credit Facility.
As a result of decreased proved oil and gas reserves at December 31,
1998, BMO has notified the Company that the Company's borrowing base was in
noncompliance and certain principal obligations were being accelerated
during 1999. Additionally, the Company was in violation of certain
negative covenants under the Credit Facility, primarily as a result of the
$35.1 million non-cash cost ceiling writedown at December 31, 1998.
On April 14, 1999, the Company and BMO signed the Second Amendment to the
Credit Facility which includes: (i) terms requiring the Company to make
principal payments to BMO of $3.0 million by May 1, 1999, $3.0 million by
May 31, 1999 and $1.0 million by the first of each month during the period July
through October 1999, inclusive; (ii) terms requiring that all outstanding
borrowings bear interest at the prime rate plus 3.5%; (iii) a waiver of all
negative covenant violations until October 15, 1999 (the "re-determination
date"); (iv) revised negative covenant provisions which take effect on the re-
determination date; (v) a requirement to submit a revised reserve report to
BMO by October 1, 1999 for a re-determination of the borrowing base; (vi) a
requirement that all proceeds from the sales of oil and gas properties,
additional debt financings or equity offerings, prior to the re-determination
date, must be used to reduce the principal amount outstanding under the Credit
Facility; and (vii) a requirement for a $300,000 amendment fee payable to BMO
at the re-determination date. At the re-determination date, the Company will
be required to make additional payments of principal to the extent its
outstanding borrowings exceed the borrowing base. To fulfill the May 1999
principal and interest obligations, management plans to sell certain oil and
gas property interests to business partners, investors and affiliated entities.
All other principal and interest obligations are expected to be fulfilled
through available cash flows, additional property sales or other financing
sources, including the possible issuance of additional equity securities as
well as identifying additional sources for debt financing.
On April 14, 1999, the Company signed a $4.7 million note payable with
one its suppliers, Veritas DGC Land, Inc. (the "Veritas Note Payable"), for
the outstanding balance due to Veritas for past services provided in 1998 and
1999. The balance due Veritas was $3.8 million at December 31, 1998, and
F-19
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
has been classified as long-term debt in the accompanying financial
statements. The principal obligation under the Veritas Note Payable is due
on April 15, 2001. Management plans to fulfill the principal obligation
under the Veritas Note Payable from available cash flows, property sales and
other financing sources.
On April 14, 1999, the Company also signed an agreement (the "Warrant
Agreement") to issue warrants that entitle Veritas to subscribe and
purchase shares of the Company's Common Stock in lieu of receiving cash
payments for the accrued interest obligations under the Veritas Note
Payable. The Warrant Agreement requires the Company to issue warrants to
Veritas in conjunction with the signing of the Warrant Agreement, as well
as on the six, 12 and 18 month anniversaries of the Warrant Agreement. The
warrants to be issued must equal 9% of the then current outstanding
principal balance of the Veritas Note Payable. The number of shares to be
issued upon exercise of the warrants will be determined on a five-day average
closing price of the Company's Common Stock. The exercise price of each
warrant is $0.01 per share. The Company has the option, in lieu of issuing
warrants, at the 12 and 18 month anniversaries to make a cash payment to
Veritas, equivalent to 9% of the then current principal balance of the
Veritas Note Payable. Under the terms of the Warrant Agreement, all
warrants issued will expire on April 15, 2002. In addition, the Company
also signed an agreement with Veritas that (i) requires the Company to file
a registration statement with the SEC to register shares of Common Stock
that are issuable upon exercise of the above warrants and (ii) grants
certain piggy-back registration rights in connection with the warrants.
The shares required to be registered include only those shares required to
be issued at each six month anniversary.
In connection with the closing of the AHC acquisition on February 9,
1998, the Company has a note payable to AHC (the "AHC Note Payable") of $3.0
million (at December 31, 1998) which is payable on the anniversary date of
the closing as follows: $0.5 million in 1999, $1.0 million in 2000 and $1.5
million in 2001.
At December 31, 1997, the Company had a notes payable balance of
approximately $4.9 million which represented a borrowing against a $5.0
million bank line-of-credit, another $1.0 million bank line-of-credit and a
$0.7 million term loan payable to a bank. These notes and term loan were
paid in full during February 1998 from the proceeds of the Offering.
Pursuant to a promissory note dated November 26, 1997, the C.E. Miller
Trust loaned on an unsecured basis $2.5 million to MOC, which MOC used to
fund a down payment made in connection with the Combination Transaction.
This note was paid in full during February 1998 from the proceeds of the
Offering.
F-20
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company's long-term debt consisted of the following as of December
31, 1998 and 1997 (in thousands):
1998 1997
------- -------
BMO Credit Facility $ 35,500 $ --
Veritas Note Payable 3,837 --
AHC Note Payable 3,000 --
Bank lines-of-credit and term loan -- 5,678
Promissory Note Payable to C.E. Miller Trust -- 2,500
--------- --------
Total 42,337 8,178
Less current portion of long-term debt (10,500) (7,697)
--------- --------
$ 31,837 $ 481
========= ========
The Company's minimum principal requirements as of December 31, 1998
are as follows (in thousands):
1999. . . . . . . . . . $ 10,500
2000. . . . . . . . . . 1,000
2001. . . . . . . . . . 12,337
2002. . . . . . . . . . 8,500
2003. . . . . . . . . . 8,500
Thereafter. . . . . . . 1,500
-----------
$ 42,337
===========
(7) FINANCIAL INSTRUMENTS
The following methods and assumptions were used to estimate the fair
value of each significant class of financial instruments:
F-21
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(7) FINANCIAL INSTRUMENTS (CONTINUED)
CASH, TEMPORARY CASH INVESTMENTS, ACCOUNTS RECEIVABLES, ACCOUNTS PAYABLE
AND NOTES PAYABLE
The carrying amount approximates fair value because of the short
maturity of those instruments.
LONG-TERM DEBT
The interest rate on the Credit Facility is reset every 30 days to
reflect current market rates. Consequently, the carrying value of the Credit
Facility approximates fair value.
HEDGING ARRANGEMENTS
Refer to Note 8 for a description of the Company's price hedging
arrangements and the fair values of the arrangements.
(8) RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS
The Company uses a variety of derivative instruments to manage
exposure to fluctuations in commodity prices and interest rates. To
qualify for hedge accounting, derivatives must meet the following criteria:
(i) the item to be hedged exposes the Company to price or interest rate
risk; and (ii) the derivative reduces that exposure and is designated as a
hedge.
COMMODITY PRICE HEDGES
In 1997, the Company began to periodically enter into hedging
arrangements to manage price risks related to crude oil and natural gas
sales and not for speculative purposes. The Company's hedging arrangements
apply only to a portion of its production, provide only partial price
protection against volatility in natural gas prices and limit potential
gains from future increases in prices. For financial reporting purposes,
gains and losses related to hedging are recognized as income when the
hedged transaction occurs. For the year ended December 31, 1998, the
Company had approximately $0.8 million of hedging gains which are included
in natural gas revenues in the consolidated statements of operations. For
the year ended December 31, 1998, the Company had hedged 36% of its natural
gas production, and as of December 31, 1998, the Company had .05 Bcf of
open natural gas contracts for the months of February 1999 and March 1999.
Subsequent to December 31, 1998, the Company entered into additional
F-22
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(8) RISK MANAGEMENT ACTIVITIES AND DERIVATIVE TRANSACTIONS (CONTINUED)
natural gas contracts for approximately .39 Bcf for the time period of April
1999 to June 1999. Open contracts totaling .05 Bcf have been settled
subsequently in 1999, resulting in hedge profits of approximately $0.01 million.
INTEREST RATE HEDGE
The Company entered into an interest rate swap agreement, effective
November 2, 1998, to exchange the variable rate interest payment obligation
under the Credit Facility without exchanging the underlying principal
amount. This agreement converts the variable rate debt to fixed rate debt
to reduce the impact of interest rate fluctuations. The notional amount is
used to measure interest to be paid or received and does not represent the
exposure to credit loss. The notional amount of the Company's interest
rate swap was $25.0 million at December 31, 1998, and had a fair value of
approximately $0.2 million. The difference between the amounts paid and
received under the swap is accrued and recorded as an adjustment to
interest expense over the term of the hedged agreement, which was to expire
February 9, 2001. Subsequent to year-end, the Company terminated its
interest rate swap agreement and received $0.3 million, which will be
recognized in earnings ratably as the related outstanding loan balance is
amortized.
(9) COMMITMENTS AND CONTINGENCIES
LEASING ARRANGEMENTS
The Company leases its office building in Traverse City, Michigan from
a related party. The lease term is for five years beginning in 1996 and
contains an annual 4% escalation clause. The Company also leases office
space in Houston, Texas; Jackson, Mississippi; and Columbia, Mississippi;
as well as warehouse space in Columbia, Mississippi. The lease agreements
in Houston and Jackson were signed by the Company in September 1997 and
April 1998, respectively. Each lease has a five year term. The lease for
office and warehouse space in Columbia was assumed through the purchase of
certain crude oil and natural gas properties from AHC in February 1998, as
more fully discussed in Note 1. The Columbia lease term ends in June 2001.
Future minimum lease payments required of the Company for years ending
December 31, are as follows (in thousands):
F-23
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(9) COMMITMENTS AND CONTINGENCIES (CONTINUED)
1999 . . . . . . . . . . . . . $ 254
2000 . . . . . . . . . . . . . 255
2001 . . . . . . . . . . . . . 210
2002 . . . . . . . . . . . . . 142
2003 . . . . . . . . . . . . . 31
Thereafter . . . . . . . . . . . --
-----
$ 892
=====
Total net rent expense under these lease arrangements was $198,547,
$103,464 and $59,735 for the years ended December 31, 1998, 1997 and 1996,
respectively.
EMPLOYEE BENEFIT PLAN
The Company has a qualified 401(k) savings plan (the "Plan") covering
substantially all eligible employees. The Plan provides for discretionary
matching contributions by the Company. Contributions charged against
operations totaled $66,359, $64,348 and $42,278 for the years ended
December 31, 1998, 1997 and 1996, respectively.
TAX CREDIT AND ROYALTY PARTICIPATION PROGRAMS
Various employees were eligible to participate in the Company's Tax
Credit and Royalty Participation Programs, which were designed to provide
incentive for certain key employees of the Company. Under the programs, the
employees were entitled to receive cash payments from the Company, based on
overriding royalty working interests, fees, reimbursements and other
financial items. These payments to the employees, which were charged
against operations, totaled $54,611, $134,916 and $116,236 for the years
ended December 31, 1998, 1997 and 1996, respectively. These programs were
terminated upon the consummation of the Offering.
OTHER
In the normal course of business, the Company may be a party to
certain lawsuits and administrative proceedings. Management cannot predict
F-24
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(9) COMMITMENTS AND CONTINGENCIES (CONTINUED)
the ultimate outcome of any pending or threatened litigation or of actual
or possible claims; however, management believes resulting liabilities, if
any, will not have a material adverse impact upon the Company's financial
position or results of operations.
(10) STOCK-BASED COMPENSATION
During 1997, the Company adopted the Stock Option and Restricted Stock
Plan of 1997 (the "1997 Plan"). The Board of Directors contemplates that
the 1997 Plan primarily will be used to grant stock options. However, the
1997 Plan permits grants of restricted stock and tax benefit rights if
determined to be desirable to advance the purposes of the 1997 Plan. These
stock options, restricted stock and tax benefit rights are collectively
referred to as "Incentive Awards." Persons eligible to receive Incentive
Awards under the 1997 Plan are directors, corporate officers and other
full-time employees of the Company and its subsidiaries. A maximum of
1.2 million shares of Common Stock (subject to certain antidilution
adjustments) are available for Incentive Awards under the 1997 Plan. Upon
consummation of the Offering in February 1998, a total of 577,850 stock
options were granted by the Company to directors, corporate officers and
other full-time employees of the Company. Subsequent to February 1998,
54,600 incentive stock options were issued to new employees under the 1997
Plan. Additionally, upon consummation of the Offering, 109,500 shares of
restricted stock were granted to certain employees. Since the above stock
options have been granted at market price, no compensation cost has been
recognized for stock options granted under the 1997 Plan. At the time of
the issuance of the restricted stock, compensation expense of approximately
$0.9 million was deferred. The restricted stock will begin to vest at
cumulative increments of one-half of the total number of restricted stock
of Common Stock subject thereto, beginning on the first anniversary of the
date of grant. Because the shares of restricted stock are subject to the
risk of forfeiture during the vesting period, compensation expense will be
recognized over the two-year vesting period as the risk of forfeiture passes.
Also in February 1998, the Company made a one-time grant of an
aggregate of 272,500 stock options to certain officers pursuant to the
terms of stock option agreements entered into between the Company and the
officers.
The Company accounts for all stock options issued under the provisions
and related interpretations of Accounting Principles Board Opinion ("APB")
F-25
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(10) STOCK-BASED COMPENSATION (CONTINUED)
No. 25, "Accounting for Stock Issued to Employees." In accordance with
SFAS No. 123, "Accounting for Stock-Based Compensation," the Company
intends to continue to apply APB No. 25 for purposes of determining net
income and to present the pro forma disclosures required by SFAS No. 123.
The following table sets forth the option transactions for the year
ended December 31, 1998:
AVERAGE
SHARES GRANT PRICE
------ -----------
Outstanding at January 1 . . . . . . . . . . . . -- --
Granted . . . . . . . . . . . . . . . . 904,950 $8.08
Exercised . . . . . . . . . . . . . . . -- --
Forfeited . . . . . . . . . . . . . . . (500) $8.00
-------- -----
Outstanding at December 31 . . . . . . . . . . . 904,450 $8.08
======== =====
Shares Exercisable at December 31 . . . . . . . . . -- --
-------- -----
Shares Available for Future Grant . . . . . . . . . 295,550
--------
Average Fair Value of Shares
Granted During Year . . . . . . . . . . . . $ 4.10
--------
The fair value of each option grant is estimated using the Black-
Scholes option-pricing model with the following weighted-average
assumptions used for grants in 1998: (1) dividend yield of 0%; (2)
expected volatility of 25.7%; (3) risk-free interest rate of 5.5%; and (4)
expected life of 10 years.
The following table summarizes certain information for the options
outstanding at December 31, 1998:
F-26
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(10) STOCK-BASED COMPENSATION (CONTINUED)
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
----------------------------------- --------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF REMAINING GRANT GRANT
GRANT PRICES SHARES LIFE PRICE SHARES PRICE
- ------------ ------ ---- ----- ------ -----
$5.25 to $10.38. . . . 904,450 9 years $ 8.08 -- $ --
The Company's pro forma net income (loss) and earnings (loss) per
share of common stock for 1998, had compensation costs been recorded in
accordance with SFAS No. 123, are presented below (in thousands except per
share data):
AS REPORTED PRO FORMA
----------- ---------
Net income (loss) . . . . . . . . . . $(41,800) $(42,229)
Earnings (loss) per share of Common Stock
Basic. . . . . . . . . . . . . . $ (3.75) $ (3.79)
======== ========
Diluted . . . . . . . . . . . . . $ (3.75) $ (3.79)
======== ========
The effects of applying SFAS No. 123 in this pro forma disclosure
should not be interpreted as being indicative of future effects.
(11) RELATED PARTY TRANSACTIONS
In July 1996, the Company sold the building it occupies to a related
party and subsequently leased a substantial portion of the building under
the terms of a five-year lease agreement (see Note 9). The Company realized
a gain on the sale of the property of approximately $160,000. This gain was
deferred and is being amortized in proportion to the gross rental charges
under the operating lease.
F-27
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(11) RELATED PARTY TRANSACTIONS (CONTINUED)
The Company provides technical and administrative services to a
corporation controlled by a related party. In connection with this
arrangement, $200,000, $200,000 and $100,000 were recognized as management
fee income (see Note 14) for the years ended December 31, 1998, 1997 and
1996, respectively.
A certain stockholder and director of the Company has controlling
interest in a corporation that is the operator of jointly owned properties.
Payments to this operator for the Company's proportionate share of
leasehold, seismic, drilling and operating expenses amounted to $7,370,718,
$2,038,938 and $2,878,175 in 1998, 1997 and 1996, respectively. This
operator also paid the Company crude oil and natural gas revenues as
disclosed in Note 15.
A certain stockholder and director of the Company is a principal in an
organization that provides consulting services to the Company. Consulting
fees paid to this organization amounted to $30,738 and $23,514 for 1997 and
1996, respectively. There were no consulting fees paid to this
organization in 1998.
An affiliated entity has signed an agreement to purchase up to a
maximum of $6.0 million of the Company's proved or unproved properties
prior to May 31, 1999.
(12) CONCENTRATIONS OF RISK
The Company extends credit to various companies in the oil and gas
industry in the normal course of business. Within this industry, certain
concentrations of credit risk exist. The Company, in its role as operator
of co-owned properties, assumes responsibility for payment to vendors for
goods and services related to joint operations and extends credit to co-
owners of these properties.
This concentration of credit risk may be similarly affected by changes
in economic or other conditions and may, accordingly, impact the Company's
overall credit risk. The Company periodically monitors its customers' and
co-owners' financial conditions.
The Company also has a significant concentration of properties in the
Mississippi Salt Basin, which are affected by changes in economic and other
conditions, including but not limited to crude oil and natural gas prices
and operating costs.
F-28
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(13) NON-CASH ACTIVITIES
During 1998, the Company recorded a one-time non-cash charge of
approximately $5.4 million for the termination of MOC's S corporation
status, as discussed in Note 3; acquired certain oil and gas properties
owned by non-affiliated parties for approximately $12.8 million of its
Common Stock, as discussed in Note 1; and converted an accounts payable
balance of $3.8 million into a note payable, as discussed in Note 6. During
1997, the stockholders contributed approximately $7.6 million of notes
payable to MOC as capital. During 1996, the Company converted $1.0 million
of its outstanding note payable balance to a five-year term-loan. These
non-cash activities have been excluded from the consolidated statements of
cash flows.
(14) OTHER OPERATING REVENUES
The majority of the other operating revenues are reimbursements for
general and administrative activities that the Company performs on behalf
of partners and investors in jointly owned oil and gas properties. All
other management fees that were earned for exploration and development
activities have been credited against oil and gas property costs.
(15) SIGNIFICANT CUSTOMERS
Revenues from certain customers accounted for more than 10% of total
crude oil and natural gas sales as follows:
FOR THE YEAR ENDED
DECEMBER 31,
--------------------
1998 1997 1996
---- ---- ----
Carthage Energy Services Inc. . . . . . 50% --% --%
Dan A. Hughes Company. . . . . . . . 21% 30% 19%
Amerada Hess Corporation. . . . . . . 12% 39% 51%
Muskegon Development Co . . . . . . . 7% 27% 24%
F-29
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following information was prepared in accordance with the
Supplemental Disclosure Requirements of SFAS No. 69, "Disclosures About Oil
and Gas Producing Activities."
Users of this information should be aware that the process of
estimating quantities of "proved" and "proved developed" crude oil and
natural gas reserves is very complex, requiring significant subjective
decisions in the evaluation of all available geological, engineering and
economic data for each reservoir. The data for a given reservoir also may
change substantially over time as a result of numerous factors including,
but not limited to, additional development activity, evolving production
history and continual reassessment of the viability of production under
varying economic conditions. Consequently, material revisions to existing
reserve estimates occur from time to time. Although every reasonable effort
is made to ensure that reserve estimates reported represent the most
accurate assessments possible, the significance of the subjective decisions
required and variances in available data for various reservoirs make these
estimates generally less precise than other estimates presented in
connection with financial statement disclosures.
Proved reserves represent estimated quantities of natural gas and
crude oil that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were
made.
Proved developed reserves are proved reserves expected to be
recovered, through wells and equipment in place and under operating methods
being utilized at the time the estimates were made.
The following estimates of proved reserves and future net cash flows
as of December 31, 1998, 1997 and 1996 have been prepared by S.A. Holditch
and Associates (as to Michigan Antrim Shale reserves) and Miller and Lents,
Ltd. (as to non-Michigan Antrim Shale reserves), independent petroleum
engineers. All of the Company's reserves are located in the United States.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
The following table sets forth the Company's net proved and proved
developed reserves at December 31 for each of the three years in the period
ended December 31, 1998, and the changes in the net proved reserves for
F-30
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
each of the three years in the period then ended as estimated by petroleum
engineers for the respective periods as described in the preceding
paragraph:
TOTAL
-----
OIL (MBBL) GAS (MMCF)
---------- ----------
Estimated Proved Reserves
December 31, 1995 . . . . . . . . . . . . 135.0 15,762.2
Extensions and discoveries . . . . . . . . 514.9 553.7
Purchase of reserves . . . . . . . . . . -- 1,016.1
Revisions and other changes. . . . . . . . 40.3 2,054.0
Production . . . . . . . . . . . . . (46.5) (2,030.0)
------ --------
December 31, 1996 . . . . . . . . . . . . 643.7 17,356.0
Extensions and discoveries . . . . . . . . 10.6 3,629.8
Revisions and other changes. . . . . . . . 161.6 (1,129.5)
Production . . . . . . . . . . . . . (47.4) (2,241.2)
------ --------
December 31, 1997 . . . . . . . . . . . . 768.5 17,615.1
Extensions and discoveries . . . . . . . . 130.1 5,863.7
Purchases of reserves. . . . . . . . . . 308.3 23,086.7
Revisions and other changes. . . . . . . . 63.3 (8,586.1)
Production . . . . . . . . . . . . . (247.6) (8,953.3)
Sales of reserves . . . . . . . . . . . (30.9) (104.2)
------ --------
December 31, 1998 . . . . . . . . . . . . 991.7 28,921.9
------ --------
Estimated Proved Developed Reserves
December 31, 1996 . . . . . . . . . . . 121.0 15,221.2
====== ========
December 31, 1997 . . . . . . . . . . . 130.2 13,964.4
====== ========
December 31, 1998 . . . . . . . . . . . 991.7 28,641.6
====== ========
F-31
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVES
The following information has been developed utilizing procedures
prescribed by SFAS No. 69 and based on crude oil and natural gas reserve
and production volumes estimated by the Company's petroleum engineers. It
may be useful for certain comparison purposes, but should not be solely
relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should
the Standardized Measure of Discounted Future Net Cash Flows be viewed as
representative of the current value of the Company.
The future cash flows presented below are based on sales prices and
cost rates in existence as of the date of the projections. It is expected
that material revisions to some estimates of crude oil and natural gas
reserves may occur in the future, development and production of the
reserves may occur in periods other than those assumed and actual prices
realized and costs incurred may vary significantly from those used.
Management does not rely upon the following information in making
investment and operating decisions. Such decisions are based upon a wide
range of factors, including estimates of probable as well as proved
reserves, and varying price and cost assumptions considered more
representative of a range of possible economic conditions that may be
anticipated.
The following table sets forth the Standardized Measure of Discounted
Future Net Cash Flows from projected production of the Company's crude oil
and natural gas reserves at December 31, 1998, 1997 and 1996:
F-32
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
1998 1997 1996
---- ---- ----
(In thousands)
Future revenues <F1>. . . . . . . . . . . $ 66,975 $ 54,896 $ 74,300
Future production costs <F2> . . . . . . . . (20,930) (19,091) (21,326)
Future development costs <F2>. . . . . . . . (1,532) (5,300) (4,348)
-------- -------- --------
Future net cash flows . . . . . . . . . . 44,513 30,505 48,626
Discount to present value at 10% annual rate. . . (8,088) (10,571) (18,561)
-------- -------- --------
Present value of future net revenues
before income taxes . . . . . . . . . . 36,425 19,934 30,065
Future income taxes discounted at 10%
annual rate<F3>. . . . . . . . . . . . -- -- --
-------- -------- --------
Standardized measure of discounted future net
cash flows . . . . . . . . . . . . . $ 36,425 $ 19,934 $ 30,065
======== ======== ========
_____________________
<FN>
<F1> Crude oil and natural gas revenues are based on year-end prices with
adjustments for changes reflected in existing contracts. There is no
consideration for future discoveries or risks associated with future
production of proved reserves.
<F2> Based on economic conditions at year-end. Does not include
administrative, general or financing costs. Does not consider future
changes in development or production costs.
<F3> The 1998 balance is not reduced by income taxes due to the tax basis
of the properties and a net operating loss carryforward. Does not
include income taxes for 1997 and 1996 as the Company was not subject
to federal income taxes until consummation of the Offering in
February 1998.
</FN>
F-33
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
The following table sets forth the changes in the Standardized Measure
of Discounted Future Net Cash Flows at December 31, 1998, 1997 and 1996:
1998 1997 1996
---- ---- ----
(In thousands)
New discoveries. . . . . . . . . . . . $ 9,962 $ 4,059 $ 6,318
Purchase of reserves . . . . . . . . . . 55,803 -- 1,102
Sales of reserves in place . . . . . . . . (167) -- --
Revisions to reserves. . . . . . . . . . (18,635) 350 7,887
Sales, net of production costs. . . . . . . (17,619) (5,305) (5,592)
Changes in prices . . . . . . . . . . . (11,776) (22,280) (184)
Accretion of discount. . . . . . . . . . 1,993 3,006 2,235
Changes in timing of production and other . . . (3,070) 10,039 (4,055)
-------- -------- -------
Net change during the year . . . . . . . . $ 16,491 $(10,131) $ 7,711
======== ======== =======
CAPITALIZED COST RELATED TO OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the capitalized costs relating to the
Company's natural gas and crude oil producing activities at December 31,
1998 and 1997:
F-34
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
1998 1997
---- ----
(In thousands)
Proved properties . . . . . . . . . . . . $103,272 $ 29,324
Unproved properties . . . . . . . . . . . 39,995 7,069
-------- --------
143,267 36,393
Less-Accumulated depreciation, depletion
and amortization. . . . . . . . . . . . (63,253) (12,425)
-------- --------
$ 80,014 $ 23,968
======== ========
COST INCURRED IN OIL AND GAS PRODUCING ACTIVITIES
The acquisition, exploration and development costs disclosed in the
following tables are in accordance with definitions in SFAS No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies."
Acquisition costs include costs incurred to purchase, lease or otherwise
acquire property. Exploration costs include exploration expenses,
additions to exploration wells in progress and depreciation of support
equipment used in exploration activities. Development costs include
additions to production facilities and equipment, additions to development
wells in progress and related facilities and depreciation of support
equipment and related facilities used in development activities.
The following table sets forth costs incurred related to the Company's
oil and gas activities for the years ended December 31:
F-35
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
1998 1997 1996
---- ---- ----
(In thousands)
Property acquisition costs<F1>. . . . . . . $ 60,974 $ 4,577 $ 2,264
Exploration costs . . . . . . . . . . . 32,142 2,226 2,340
Development costs . . . . . . . . . . . 17,615 2,019 1,580
-------- ------- -------
Total <F2> . . . . . . . . . . . . $110,731 $ 8,822 $ 6,184
======== ======= =======
____________________
<FN>
<F1> Includes $19,556 in 1998 and $757 in 1996 for the acquisition of
proved producing properties.
<F2> Includes $12,770 in 1998 of non-cash acquisitions of proved
producing and unproved properties in connection with the
Combination Transaction as more fully described in Note 1.
</FN>
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The following table sets forth the Company's results of operations
from oil and gas producing activities for the years ended December 31,
1998, 1997 and 1996. The results of operations below do not include general
and administrative expenses, income taxes and interest expense.
F-36
MILLER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
(16) SUPPLEMENTAL FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
1998 1997 1996
---- ---- ----
(In thousands)
Operating Revenues:
Natural gas . . . . . . . . . . . . $ 18,336 $ 5,819 $ 5,614
Crude oil and condensate . . . . . . . . 2,646 964 1,101
-------- ------- -------
Total operating revenues . . . . . . . $ 20,982 6,783 6,715
-------- ------- -------
Operating expenses:
Lease operating expenses and production taxes . $ 3,363 1,478 1,123
Depreciation, depletion and amortization. . . 15,933 2,520 2,629
Cost ceiling writedown . . . . . . . . 35,085 -- --
Total operating expenses . . . . . . . 54,381 3,998 3,752
-------- ------- -------
Results of operations . . . . . . . . . . $(33,399) $ 2,785 $ 2,963
======== ======= =======
F-37
MILLER EXPLORATION COMPANY
SUPPLEMENTAL QUARTERLY FINANCIAL DATA
UNAUDITED QUARTERLY FINANCIAL INFORMATION
QUARTER ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
(In thousands, except per share data)
1998
Total Operating Revenues. . . . . . . . $ 4,236 $ 5,727 $ 5,858 $ 5,990
Operating Income (Loss) . . . . . . . . 39 1,066 592 (37,742)
Net Income (Loss) . . . . . . . . . . (5,581) 601 100 (36,920)
Earnings per share:
Basic . . . . . . . . . . . . . (0.79) 0.05 0.01 (3.02)
Diluted. . . . . . . . . . . . . (0.79) 0.05 0.01 (3.02)
1997
Total Operating Revenues. . . . . . . . $ 2,308 $ 1,538 $ 1,685 $ 1,881
Operating Income (Loss) . . . . . . . . 903 115 242 (32)
Net Income (Loss) . . . . . . . . . . 721 (93) (290) (310)
1996
Total Operating Revenues. . . . . . . . $ 1,440 $ 1,622 $ 1,868 $ 2,180
Operating Income . . . . . . . . . . 288 382 677 420
Net Income . . . . . . . . . . . . 81 125 352 70
F-38
UNAUDITED PRO FORMA FINANCIAL DATA
The pro forma unaudited financial data set forth below has been
prepared to give effect to the Combination Transaction and the Offering and
the application of the estimated net proceeds therefrom. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Overview." The pro forma unaudited statements of operations for the years
ended December 31, 1998 and 1997 were prepared on the basis that the
Combination Transaction and the Offering occurred on January 1, 1997. Pro
forma data gives effect to the revenues and direct operating expenses of
the properties acquired from the non-affiliated participants in the
Combination Transaction (the "Acquired Properties"). In addition, the pro
forma data are based on assumptions and include adjustments as explained in
the notes to the unaudited pro forma financial statements and are not
necessarily indicative of the results of future operations of the Company.
The following financial information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the combined financial statements.
MILLER EXPLORATION COMPANY
PRO FORMA STATEMENTS OF OPERATIONS
(In thousands, except per share data)
(Unaudited)
FOR THE YEAR
ENDED DECEMBER 31,
--------------------
1998 1997
---- ----
Revenues:
Natural gas<F1>. . . . . . . . . . . . . . . . $ 19,810 $ 20,774
Crude oil and condensate<F1> . . . . . . . . . . . 2,833 3,711
Other operating revenues. . . . . . . . . . . . . 829 629
-------- -------
Total operating revenues . . . . . . . . . . . . 23,472 25,114
-------- -------
Operating expenses:
Lease operating expenses and production taxes<F1> . . . . 3,571 2,423
Depreciation, depletion and amortization<F2> . . . . . . 16,537 7,812
General and administrative<F3>. . . . . . . . . . . 3,175 2,606
Cost ceiling writedown . . . . . . . . . . . . . 34,428 --
-------- -------
Total operating expenses . . . . . . . . . . . . 57,711 12,841
-------- -------
F-39
Operating income (loss) . . . . . . . . . . . . . . (34,239) 12,273
-------- -------
Interest expense<F4> . . . . . . . . . . . . . . . (1,635) (1,125)
-------- -------
Income (loss) before income taxes . . . . . . . . . . . (35,874) 11,148
-------- -------
Provision (credit) for income taxes<F5> . . . . . . . . . (716) 2,710
-------- -------
Net income (loss) . . . . . . . . . . . . . . . . $(35,158) $ 8,438
======== =======
Earnings (loss) per share<F6>:
Basic . . . . . . . . . . . . . . . . . . . $ (2.81) $ 0.68
Diluted . . . . . . . . . . . . . . . . . . (2.81) 0.68
Average number of shares outstanding<F6>:
Basic . . . . . . . . . . . . . . . . . . . 12,493 12,493
Diluted . . . . . . . . . . . . . . . . . . 12,493 12,493
- -----------------
<FN>
Notes to pro forma financial data (unaudited):
<F1> Includes results of operations from the Acquired Properties.
<F2> Reflects the estimated additional depreciation, depletion and
amortization expense resulting from the acquisition of the Acquired
Properties using the unit-of-production method.
<F3> Reflects estimated incremental general and administrative expenses
expected to be incurred as a direct result of increased operations
after the Combination Transaction. Such expenses are primarily from
increased salaries and additional new employees to perform
administrative and operational activities ($0.5 million per year) and
the elimination of the Royalty Participation Program ($0.1 million per
year). Excluded from this amount is $0.3 million of non-recurring
bonuses paid to certain employees of the Company in connection with
consummation of the Offering.
<F4> Reflects the reduction in interest expense attributable to MOC
shareholder notes being contributed in connection with the Combination
Transaction, resulting in the cancellation of the indebtedness, the
F-40
cancellation of other indebtedness with the use of proceeds from the
Offering and the increase in interest expense from the new borrowing
under the Credit Facility.
<F5> Gives pro forma effect to the application of federal and state income
taxes to the Company as if it were a taxable corporation for the
periods presented. Upon consummation of the Combination Transaction,
the Company was required to record a one-time non-cash charge to
earnings of $5.4 million in connection with establishing a deferred
tax liability on the balance sheet. This non-recurring charge has
been excluded from the statements.
<F6> Reflects the issuance of Common Stock in exchange for certain of the
Combined Assets in the Combination Transaction and the issuance of
Common Stock in the Offering.
</FN>
F-41
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
2.1 Exchange and Combination Agreement dated November 12, 1997.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(a) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(b) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.2(c) Letter Agreement amending Exchange and Combination Agreement.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.3(a) Agreement for Purchase and Sale dated November 25, 1997
between Amerada Hess Corporation and Miller Oil Corporation.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
2.3(b) First Amendment to Agreement for Purchase and Sale dated
January 7, 1998. Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and
here incorporated by reference.
3.1 Certificate of Incorporation of the Registrant. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
3.2 Bylaws of the Registrant. Previously filed as an exhibit to
the Company's Quarterly Report on Form 10-Q for the quarter
ended June 30, 1998, and here incorporated by reference.
4.1 Certificate of Incorporation. See Exhibit 3.1.
4.2 Bylaws. See Exhibit 3.2.
4.3 Form of Specimen Stock Certificate. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.1(a) Stock Option and Restricted Stock Plan of 1997.<F*>
Previously filed as an exhibit to the Company's Annual Report
on Form 10-K for the year ended December 31, 1997, and here
incorporated by reference.
10.1(b) Form of Stock Option Agreement.<F*> Previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.1(c) Form of Restricted Stock Agreement.<F*> Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.2 Form of Director and Officer Indemnity Agreement. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.<F*>
10.3 Form of Employment Agreement for Kelly E. Miller, William J.
Baumgartner, Lew P. Murray and Charles A. Morrison. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.<F*>
10.4 Lease Agreement between Miller Oil Corporation and C.E. and
Betty Miller, dated July 24, 1996. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.5 Letter Agreement dated November 10, 1997, between Miller Oil
Corporation and C.E. Miller, regarding sale of certain assets.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
10.6 Amended Service Agreement dated January 1, 1997, between
Miller Oil Corporation and Eagle Investments, Inc. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
-2-
10.7 Form of Registration Rights Agreement (included as Exhibit E
to Exhibit 2.1). Previously filed as an exhibit to the
Company's Registration Statement on Form S-1 (333-40383), and
here incorporated by reference.
10.8 Consulting Agreement dated June 1, 1996 between Miller Oil
Corporation and Frank M. Burke, Jr., with amendment.
Previously filed as an exhibit to the Company's Registration
Statement on Form S-1 (333-40383), and here incorporated by
reference.
10.9 $2,500,000 Promissory Note dated November 26, 1997 between
Miller Oil Corporation and the C.E. Miller Trust. Previously
filed as an exhibit to the Company's Registration Statement on
Form S-1 (333-40383), and here incorporated by reference.
10.10 Form of Indemnification and Contribution Agreement among the
Registrant and the Selling Stockholders. Previously filed as
an exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
10.11 Credit Agreement between Miller Oil Corporation and Bank of
Montreal dated February 9, 1998. Previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.12 Guaranty Agreement by Miller Exploration Company in favor of
Bank of Montreal dated February 9, 1998. Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.13 $75,000,000 Promissory Note of Miller Oil Corporation to Bank
of Montreal dated February 9, 1998. Previously filed as an
exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.14 Mortgage (Michigan) between Miller Oil Corporation and James
Whitmore, as trustee for the benefit of Bank of Montreal,
dated February 9, 1998. Previously filed as an exhibit to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1997, and here incorporated by reference.
-3-
10.15 Mortgage, Deed of Trust, Assignment of Production, Security
Agreement and Financing Statement (Mississippi) between Miller
Oil Corporation and James Whitmore, as trustee for the benefit
of Bank of Montreal, dated February 9, 1998. Previously filed
as an exhibit to the Company's Annual Report on Form 10-K for
the year ended December 31, 1997, and here incorporated by
reference.
10.16 Mortgage, Deed of Trust, Assignment of Production, Security
Agreement and Financing Statement (Texas) between Miller Oil
Corporation and James Whitmore, as trustee for the benefit of
Bank of Montreal, dated February 9, 1998. Previously filed as
an exhibit to the Company's Annual Report on Form 10-K for the
year ended December 31, 1997, and here incorporated by
reference.
10.17 First Amendment to Credit Agreement between Miller Oil
Corporation and Bank of Montreal dated June 24, 1998.
10.18 Second Amendment to Credit Agreement between Miller Oil
Corporation and Bank of Montreal dated April 14, 1999.
10.19 Agreement between Eagle Investments, Inc. and Miller Oil
Corporation, dated April 1, 1999.
10.20 $4,696,040.60 Note between Miller Exploration Company and
Veritas DGC Land, Inc., dated April 14, 1999.
10.21 Warrant between Miller Exploration Company and Veritas DGC
Land, Inc., dated April 14, 1999.
10.22 Registration Rights Agreement between Miller Exploration
Company and Veritas DGC Land, Inc., dated April 14, 1999.
11.1 Computation of Earnings per Share.
21.1 Subsidiaries of the Registrant. Previously filed as an
exhibit to the Company's Registration Statement on Form S-1
(333-40383), and here incorporated by reference.
23.1 Consent of S.A. Holditch & Associates.
23.2 Consent of Miller and Lents, Ltd.
23.3 Consent of Arthur Andersen LLP.
-4-
24.1 Limited Power of Attorney.
27.1 Financial Data Schedule.
____________________
<F*> Management contract or compensatory plan or arrangement.
-5-